10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2010

or

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                    to                    

Commission File Number: 1-16463

PEABODY ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	13-4004153
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

701 Market Street, St. Louis, Missouri	63101-1826
(Address of principal executive offices)	(Zip Code)

(314) 342-3400

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

There were 269,170,957 shares of common stock with a par value of $0.01 per share outstanding at July 30, 2010.

INDEX

	Page
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements.
Unaudited Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2010 and 2009		1
Condensed Consolidated Balance Sheets as of June 30, 2010 (Unaudited) and December 31, 2009		2
Unaudited Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2010 and 2009		3
Unaudited Consolidated Statement of Changes in Stockholders’ Equity for the Six Months Ended June 30, 2010		4
Notes to Unaudited Condensed Consolidated Financial Statements		5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		34
Item 3. Quantitative and Qualitative Disclosures About Market Risk		47
Item 4. Controls and Procedures		47
PART II — OTHER INFORMATION
Item 1. Legal Proceedings		48
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		48
Item 5. Other Information		48
Item 6. Exhibits		50
SIGNATURE		51
EXHIBIT INDEX		52
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

PEABODY ENERGY CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(Dollars in millions, except per share data)
Revenues
Sales	$	1,569.8		$	1,206.5		$	2,954.9		$	2,486.5
Other revenues		91.6			131.7			222.1			304.7
Total revenues		1,661.4			1,338.2			3,177.0			2,791.2
Costs and expenses
Operating costs and expenses		1,174.7			969.9			2,283.4			2,050.6
Depreciation, depletion and amortization		105.1			101.2			210.6			197.5
Asset retirement obligation expense		10.9			9.6			20.4			19.0
Selling and administrative expenses		54.1			45.6			109.5			91.7
Other operating (income) loss:
Net gain on disposal or exchange of assets		(1.4	)		(10.1	)		(8.7	)		(13.4	)
(Income) loss from equity affiliates		(6.4	)		6.6			(4.8	)		10.7
Operating profit		324.4			215.4			566.6			435.1
Interest expense		57.9			48.2			107.9			99.3
Interest income		(1.6	)		(1.2	)		(2.6	)		(4.0	)
Income from continuing operations before income taxes		268.1			168.4			461.3			339.8
Income tax provision		53.4			78.4			109.5			108.6
Income from continuing operations, net of income taxes		214.7			90.0			351.8			231.2
Income (loss) from discontinued operations, net of income taxes		(0.5	)		(8.0	)		(0.9	)		26.0
Net income		214.2			82.0			350.9			257.2
Less: Net income attributable to noncontrolling interests		8.0			2.8			11.0			8.0
Net income attributable to common stockholders	$	206.2		$	79.2		$	339.9		$	249.2
Income From Continuing Operations
Basic earnings per share	$	0.77		$	0.33		$	1.27		$	0.83
Diluted earnings per share	$	0.76		$	0.32		$	1.26		$	0.83
Net Income Attributable to Common Stockholders
Basic earnings per share	$	0.77		$	0.30		$	1.27		$	0.93
Diluted earnings per share	$	0.76		$	0.29		$	1.26		$	0.93
Dividends declared per share	$	0.07		$	0.06		$	0.14		$	0.12

See accompanying notes to unaudited condensed consolidated financial statements.

1

PEABODY ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	June 30, 2010			December 31, 2009
	(Amounts in millions, except share and per
	share data)
ASSETS
Current assets
Cash and cash equivalents	$	1,157.0		$	988.8
Accounts receivable, net of allowance for doubtful accounts of $21.5 at June 30, 2010 and $18.3 at December 31, 2009		393.7			303.0
Inventories		363.4			325.1
Assets from coal trading activities, net		197.8			276.8
Deferred income taxes		57.3			40.0
Other current assets		161.0			255.3
Total current assets		2,330.2			2,189.0
Property, plant, equipment and mine development
Land and coal interests		7,585.5			7,557.3
Buildings and improvements		972.2			908.0
Machinery and equipment		1,489.8			1,391.2
Less: accumulated depreciation, depletion and amortization		(2,801.1	)		(2,595.0	)
Property, plant, equipment and mine development, net		7,246.4			7,261.5
Investments and other assets		521.2			504.8
Total assets	$	10,097.8		$	9,955.3
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	35.2		$	14.1
Liabilities from coal trading activities, net		79.9			110.6
Accounts payable and accrued expenses		1,101.3			1,187.7
Total current liabilities		1,216.4			1,312.4
Long-term debt, less current maturities		2,727.6			2,738.2
Deferred income taxes		320.5			299.1
Asset retirement obligations		467.7			452.1
Accrued postretirement benefit costs		913.5			914.1
Other noncurrent liabilities		481.9			483.5
Total liabilities		6,127.6			6,199.4
Stockholders’ equity
Preferred Stock - $0.01 per share par value; 10,000,000 shares authorized, no shares issued or outstanding as of June 30, 2010 or December 31, 2009		—			—
Series A Junior Participating Preferred Stock - 1,500,000 shares authorized, no shares issued or outstanding as of June 30, 2010 or December 31, 2009		—			—
Perpetual Preferred Stock - 750,000 shares authorized, no shares issued or outstanding as of June 30, 2010 or December 31, 2009		—			—
Series Common Stock - $0.01 per share par value; 40,000,000 shares authorized, no shares issued or outstanding as of June 30, 2010 or December 31, 2009		—			—
Common Stock - $0.01 per share par value; 800,000,000 shares authorized, 277,760,081 shares issued and 268,938,289 shares outstanding as of June 30, 2010 and 276,848,279 shares issued and 268,203,815 shares outstanding as of December 31, 2009		2.8			2.8
Additional paid-in capital		2,095.2			2,067.7
Retained earnings		2,486.1			2,183.8
Accumulated other comprehensive loss		(299.7	)		(183.5	)
Treasury shares, at cost: 8,821,792 shares as of June 30, 2010 and 8,644,464 shares as of December 31, 2009		(329.1	)		(321.1	)
Peabody Energy Corporation’s stockholders’ equity		3,955.3			3,749.7
Noncontrolling interests		14.9			6.2
Total stockholders’ equity		3,970.2			3,755.9
Total liabilities and stockholders’ equity	$	10,097.8		$	9,955.3

See accompanying notes to unaudited condensed consolidated financial statements.

2

PEABODY ENERGY CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six Months Ended June 30,
	2010			2009
	(Dollars in millions)
Cash Flows From Operating Activities
Net income	$	350.9		$	257.2
(Income) loss from discontinued operations, net of income taxes		0.9			(26.0	)
Income from continuing operations, net of income taxes		351.8			231.2
Adjustments to reconcile income from continuing operations, net of income taxes to net cash provided by operating activities:
Depreciation, depletion and amortization		210.6			197.5
Deferred income taxes		69.7			54.1
Share-based compensation		22.3			17.3
Net gain on disposal or exchange of assets		(8.7	)		(13.4	)
(Income) loss from equity affiliates		(4.8	)		10.7
Changes in current assets and liabilities:
Accounts receivable, including securitization		(89.3	)		70.9
Inventories		(38.3	)		(169.2	)
Net assets from coal trading activities		(5.2	)		33.7
Other current assets		19.2			(28.5	)
Accounts payable and accrued expenses		(63.1	)		(188.2	)
Asset retirement obligations		14.4			15.4
Workers’ compensation obligations		3.9			1.4
Accrued postretirement benefit costs		13.2			6.1
Contributions to pension plans		(20.1	)		(5.1	)
Other, net		(9.3	)		(7.5	)
Net cash provided by continuing operations		466.3			226.4
Net cash provided by (used in) discontinued operations		(9.9	)		5.1
Net cash provided by operating activities		456.4			231.5
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development		(187.5	)		(81.9	)
Investment in Prairie State Energy Campus		(30.5	)		(24.5	)
Federal coal lease expenditures		—			(123.6	)
Proceeds from disposal of assets, net of notes receivable		6.1			35.4
Investments in equity affiliates and joint ventures		(17.4	)		(10.0	)
Other, net		(4.4	)		(3.4	)
Net cash used in continuing operations		(233.7	)		(208.0	)
Net cash used in discontinued operations		—			(0.3	)
Net cash used in investing activities		(233.7	)		(208.3	)
Cash Flows From Financing Activities
Proceeds from long-term debt		500.0			—
Payments of long-term debt		(495.7	)		(6.0	)
Dividends paid		(37.6	)		(32.1	)
Payment of debt issuance costs		(21.9	)		—
Proceeds from stock options exercised		2.4			0.6
Other, net		(1.7	)		10.6
Net cash used in financing activities		(54.5	)		(26.9	)
Net change in cash and cash equivalents		168.2			(3.7	)
Cash and cash equivalents at beginning of period		988.8			449.7
Cash and cash equivalents at end of period	$	1,157.0		$	446.0

See accompanying notes to unaudited condensed consolidated financial statements.

3

PEABODY ENERGY CORPORATION

UNAUDITED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

	Peabody Energy Corporation’s Stockholders’ Equity
			Additional								Accumulated
			Paid-in					Retained			Other Comprehensive			Noncontrolling			Total Stockholders’
	Common Stock		Capital		Treasury Stock			Earnings			Loss			Interests			Equity
	(Dollars in millions)
December 31, 2009	$	2.8	$	2,067.7	$	(321.1	)	$	2,183.8		$	(183.5	)	$	6.2		$	3,755.9
Comprehensive income:
Net income		—		—		—			339.9			—			11.0			350.9
Decrease in fair value of cash flow hedges (net of $67.9 tax benefit)		—		—		—			—			(132.2	)		—			(132.2	)
Postretirement plans and workers’ compensation obligations (net of $11.5 tax provision)		—		—		—			—			16.0			—			16.0
Comprehensive income									339.9			(116.2	)		11.0			234.7
Dividends paid		—		—		—			(37.6	)		—			—			(37.6	)
Share-based compensation		—		22.3		—			—			—			—			22.3
Stock options exercised		—		2.4		—			—			—			—			2.4
Employee stock purchases		—		2.8		—			—			—			—			2.8
Shares relinquished		—		—		(8.0	)		—			—			—			(8.0	)
Distributions to noncontrolling interests		—		—		—			—			—			(2.3	)		(2.3	)
June 30, 2010	$	2.8	$	2,095.2	$	(329.1	)	$	2,486.1		$	(299.7	)	$	14.9		$	3,970.2

See accompanying notes to unaudited condensed consolidated financial statements.

4

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(1) Basis of Presentation

     The condensed consolidated financial statements include the accounts of Peabody Energy Corporation (the Company) and its affiliates. All intercompany transactions, profits and balances have been eliminated in consolidation.

     The accompanying condensed consolidated financial statements as of June 30, 2010 and for the three and six months ended June 30, 2010 and 2009, and the notes thereto, are unaudited. However, in the opinion of management, these financial statements reflect all normal, recurring adjustments necessary for a fair presentation of the results of the periods presented. The balance sheet information as of December 31, 2009 has been derived from the Company’s audited consolidated balance sheet. The results of operations for the six months ended June 30, 2010 are not necessarily indicative of the results to be expected for future quarters or for the year ending December 31, 2010.

     The Company classifies items within discontinued operations in the unaudited condensed consolidated statements of operations when the operations and cash flows of a particular component (defined as operations and cash flows that can be clearly distinguished, operationally and for financial reporting purposes, from the rest of the entity) of the Company have been (or will be) eliminated from the ongoing operations of the Company as a result of a disposal transaction, and the Company will no longer have any significant continuing involvement in the operations of that component. See Note 3 for additional details related to discontinued operations.

     Certain amounts in prior periods have been reclassified to conform with the current year presentations with no effect on previously reported net income or stockholders’ equity.

(2) Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented

     In January 2010, the Financial Accounting Standards Board (FASB) issued accounting guidance that requires new fair value disclosures, including significant transfers in and out of Level 1 and Level 2 fair-value measurements and a description of the reasons for the transfers. In addition, the guidance requires new disclosures regarding activity in Level 3 fair value measurements, including a gross basis reconciliation. The new disclosure requirements became effective for interim and annual periods beginning January 1, 2010, except for the disclosure of activity within Level 3 fair value measurements, which is effective for fiscal years beginning after December 15, 2010 (January 1, 2011 for the Company). While the adoption of the guidance had an impact on the Company’s disclosures, it did not affect the Company’s results of operations, financial condition or cash flows. Further, the adoption of the gross presentation of Level 3 activity will also impact the Company’s disclosures, but will not affect its results of operations, financial condition or cash flows.

     In June 2009, the FASB issued accounting guidance on consolidations which clarifies that the determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance. The guidance also requires an ongoing reassessment of whether a company is the primary beneficiary of a variable interest entity, and additional disclosures about a company’s involvement in variable interest entities and any associated changes in risk exposure. The guidance became effective January 1, 2010, at which time there was no impact on the Company’s results of operations, financial condition or cash flows. The Company will continue monitoring and assessing its business ventures in accordance with the guidance.

     In June 2009, the FASB issued accounting guidance that seeks to improve the relevance, representational faithfulness and comparability of the information that a reporting entity provides in its financial statements about a transfer of financial assets; the effects of a transfer on its financial position, financial performance and cash flows; and a transferor’s continuing involvement, if any, in transferred financial assets. The guidance, which became effective January 1, 2010, had an impact on the Company’s disclosures for its accounts receivable securitization program, but did not affect the Company’s results of operations, financial condition or cash flows.

5

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(3) Discontinued Operations

     Discontinued operations reflect the spin off of Patriot Coal Corporation (Patriot) and operations recently divested, as well as certain non-strategic mining assets held for sale where the Company has committed to the divestiture of such assets. See Note 2 to the Consolidated Financial Statements contained in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009 for additional information regarding the Company’s discontinued operations.

     Revenues resulting from discontinued operations (including assets held for sale) were $17.1 million and $74.3 million for the three months ended June 30, 2010 and 2009, respectively, and $44.7 million and $154.9 million for the six months ended June 30, 2010 and 2009, respectively. Income (loss) before income taxes reflects losses of $0.7 million and $12.0 million for the three months ended June 30, 2010 and 2009, respectively; a loss of $1.4 million for the six months ended June 30, 2010 and income of $42.7 million for the six months ended June 30, 2009. The income for the six months ended June 30, 2009 related primarily to a coal excise tax refund. The income tax benefit resulting from discontinued operations was $0.2 million and $4.0 million for the three months ended June 30, 2010 and 2009 respectively; a benefit of $0.5 million for the six months ended June 30, 2010 and a provision of $16.7 million for the six months ended June 30, 2009.

     Total assets related to discontinued operations were $25.0 million and $40.6 million as of June 30, 2010 and December 31, 2009, respectively. Total liabilities associated with discontinued operations were $25.0 million and $47.1 million as of June 30, 2010 and December 31, 2009, respectively.

(4) Assets and Liabilities from Coal Trading Activities

     The fair value of assets and liabilities from coal trading activities is set forth below:

	June 30, 2010						December 31, 2009
	(Dollars in millions)
	Gross Basis			Net Basis			Gross Basis			Net Basis
Assets from coal trading activities	$	816.2		$	197.8		$	949.8		$	276.8
Liabilities from coal trading activities		(708.1	)		(79.9	)		(779.3	)		(110.6	)
Subtotal		108.1			117.9			170.5			166.2
Net margin posted (held) (1)		9.8			—			(4.3	)		—
Net fair value of coal trading positions	$	117.9		$	117.9		$	166.2		$	166.2

⁽¹⁾ Represents margin posted with counterparties of $9.8 million at June 30, 2010; and margin held from counterparties of $22.4 million net of margin posted with counterparties of $18.1 million at December 31, 2009.

     As of June 30, 2010, forward contracts made up 53% and 43% of the Company’s trading assets and liabilities, respectively; financial swaps represent most of the remaining balances. The net fair value of coal trading positions designated as cash flow hedges of anticipated future sales was an asset of $10.8 million and $93.0 million as of June 30, 2010 and December 31, 2009, respectively.

     As of June 30, 2010, the estimated future realization of the value of the Company’s trading portfolio was as follows:

Year of	Percentage of
Expiration	Portfolio Total
2010		26	%
2011		70	%
2012		4	%
		100	%

6

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     At June 30, 2010, 47% of the Company’s credit exposure related to coal trading activities with investment grade counterparties and 53% with non-investment grade counterparties.

(5) Inventories

     Inventories consisted of the following:

	June 30, 2010		December 31, 2009
	(Dollars in millions)
Materials and supplies	$	98.8	$	106.5
Raw coal		77.4		80.5
Saleable coal		187.2		138.1
Total	$	363.4	$	325.1

(6) Income Taxes

     The income tax rate differed from the United States (U.S.) federal statutory rate as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(Dollars in millions)
Federal statutory rate	$	93.8		$	59.0		$	161.4		$	119.0
Excess depletion		(8.9	)		(18.1	)		(18.6	)		(34.8	)
Foreign earnings rate differential		(13.3	)		(8.2	)		(27.3	)		(23.7	)
Remeasurement of foreign income tax accounts		(19.3	)		47.7			(13.9	)		46.8
State income taxes, net of U.S. federal tax benefit		2.5			3.2			4.9			2.0
Tax credits		(3.9	)		(6.1	)		(7.5	)		(10.4	)
Changes in valuation allowance		13.7			5.7			18.1			6.5
Changes in tax reserves		(8.9	)		(3.5	)		(7.1	)		3.1
Other, net		(2.3	)		(1.3	)		(0.5	)		0.1
Total provision	$	53.4		$	78.4		$	109.5		$	108.6

     As a result of the completion of the Internal Revenue Service (IRS) examination of the 2005 federal income tax year, the Company reduced its gross unrecognized tax benefits by $15.2 million, which is reflected as a benefit in the income tax provision for the three and six months ended June 30, 2010. The Company and the IRS did not reach an agreement on the adjustment of interest income accrued by a foreign subsidiary through the alternative dispute resolution program (Fast Track Settlement) for the 2006 federal income tax year. The Company will now begin the formal IRS appeals process to resolve the remaining issue, which could take one to two years to complete.

     The change in the deferred tax balances during the three and six months ended June 30, 2010 was driven by utilization of net operating loss carryforwards and changes in the value of the Company’s cash flow hedges.

     The change in the valuation allowance during the three and six months ended June 30, 2010 was primarily due to reserves recorded against Alternative Minimum Tax and general business credits.

7

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(7) Long-Term Debt

     The Company’s total indebtedness as of June 30, 2010 and December 31, 2009 consisted of the following:

	June 30,		December 31,
	2010		2009
	(Dollars in millions)
Term Loan	$	500.0	$	490.3
Convertible Junior Subordinated Debentures due 2066		372.4		371.5
7.375% Senior Notes due November 2016		650.0		650.0
6.875% Senior Notes due March 2013		650.0		650.0
7.875% Senior Notes due November 2026		247.2		247.1
5.875% Senior Notes due March 2016		218.1		218.1
6.84% Series C Bonds due December 2016		33.0		33.0
6.34% Series B Bonds due December 2014		15.0		15.0
Capital lease obligations		69.1		67.5
Fair value hedge adjustment		6.8		8.4
Other		1.2		1.4
Total	$	2,762.8	$	2,752.3

Credit Facility

     On June 18, 2010 the Company entered into an unsecured credit agreement (the Credit Agreement) which established a $2.0 billion Credit Facility (the Credit Facility) and replaced the Company’s third amended and restated credit agreement dated as of September 15, 2006. The Credit Agreement provides for a $1.5 billion revolving credit facility (the Revolver) and a $500.0 million term loan facility (the Term Loan). The Company has the option to request an increase in the capacity of the Credit Facility, provided the aggregate increase for the Revolver and Term Loan does not exceed $250.0 million and the minimum amount of the increase is $25.0 million, assuming conditions are met under the Credit Agreement. The Revolver also includes a swingline sub-facility where up to $50.0 million is available for same-day borrowings. The Revolver commitments and the Term Loan under the Credit Facility will mature on June 18, 2015.

     The Revolver replaced the Company’s previous $1.8 billion revolving credit facility and the Term Loan replaced the Company’s previous term loan facility (the previous term loan had a balance of $490.3 million at the time of replacement and at December 31, 2009). The Company capitalized $21.9 million in financing costs, which will be amortized to interest expense over the five year term of the Credit Facility. The Company also had refinancing charges of $9.3 million, which primarily consisted of the cancellation of an interest rate swap associated with the Company’s previous credit facility. The $500.0 million of proceeds from the Term Loan was used to pay off the $490.3 million balance due on the Company’s previous term loan facility.

     All borrowings under the Credit Agreement (other than swingline borrowings and borrowings denominated in currencies other than U.S. dollars) bear interest, at the Company’s option, at either a “base rate” or a “eurocurrency rate”, as defined in the Credit Agreement, plus in each case, a rate adjustment based on the Company’s leverage ratio, as defined in the Credit Agreement, ranging from 2.50% to 1.25% per year for borrowings bearing interest at the “base rate” and from 3.50% to 2.25% per year for borrowings bearing interest at the “eurocurrency rate” (such rate added to the “eurocurrency rate,” the “Eurocurrency Margin”). Swingline borrowings bear interest at a “BBA LIBOR” rate equal to the rate at which deposits in U.S. dollars for a one month term are offered in the interbank eurodollar market, as determined by the administrative agent, plus the Eurocurrency Margin. Borrowings denominated in currencies other than U.S. dollars will bear interest at the “eurocurrency rate” plus the Eurocurrency Margin.

     The Company pays a usage-dependent commitment fee under the Revolver, which is dependent upon the Company’s leverage ratio, as defined in the Credit Agreement, and ranges from 0.500% to 0.375% of the available unused commitment. Swingline loans are not considered usage of the revolving credit facility for purposes of calculating the commitment fee. The fee accrues quarterly in arrears.

8

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     In addition, the Company pays a letter of credit fee calculated at a rate dependent on the Company’s leverage ratio, as defined in the Credit Agreement, ranging from 3.50% to 2.25% per year of the undrawn amount of each letter of credit and a fronting fee equal to 0.125% per year of the face amount of each letter of credit. These fees are payable quarterly in arrears.

     The $500.0 million Term Loan is subject to quarterly repayment of 1.25% per quarter commencing on December 31, 2010, with the final payment of all amounts outstanding (including accrued interest) being due on June 18, 2015.

     Under the Credit Agreement, the Company must comply with certain financial covenants on a quarterly basis including a minimum interest coverage ratio and a maximum leverage ratio. The financial covenants also place limitations on the Company’s ability to incur debt; pay dividends; make loans, investments, advances and acquisitions; sell assets; make redemptions and repurchases of capital stock; engage in mergers or consolidations; engage in affiliate transactions; and restrict distributions from subsidiaries.

     Nearly all of the Company’s direct and indirect domestic subsidiaries guarantee all loans under the Credit Agreement. Certain of the Company’s foreign subsidiaries also, to the extent permitted by applicable law and existing contractual obligations, will be guarantors of loans made to the Company’s Dutch subsidiary.

     As of June 30, 2010, the Company had $243.9 million of letters of credit outstanding under the Revolver, with a remaining borrowing capacity of $1.2 billion.

     The interest rate payable on the Revolver and the Term Loan was LIBOR plus 2.50%, or 2.85%, at June 30, 2010.

Other Long-Term Debt

     There were no other significant changes to the Company’s long-term debt since December 31, 2009.

(8) Comprehensive Income

     The following table sets forth the after-tax components of comprehensive income:

	Three Months Ended June 30,					Six Months Ended June 30,
	2010			2009		2010			2009
	(Dollars in millions)
Net income	$	214.2		$	82.0	$	350.9		$	257.2
Increase (decrease) in fair value of cash flow hedges, net of income taxes		(187.2	)		182.0		(132.2	)		238.9
Amortization of actuarial loss and prior service cost associated with postretirement plans and workers compensation obligations, net of income taxes		8.5			7.6		16.0			(2.1	)
Comprehensive income	$	35.5		$	271.6	$	234.7		$	494.0

     Comprehensive income differs from net income by the amount of unrealized gain or loss resulting from valuation changes of the Company’s cash flow hedges (which include fuel and explosives hedges, currency forwards, traded coal index contracts and interest rate swaps) and the change in actuarial loss and prior service cost during the periods. The values of the Company’s cash flow hedging instruments can be affected by changes in interest rates, crude oil, diesel fuel, natural gas and coal prices and the U.S. dollar/Australian dollar exchange rate. The change in the value of the cash flow hedges during 2010 was primarily due to the weakening of the Australian dollar against the U.S. dollar and lower fuel prices.

9

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(9) Earnings per Share (EPS)

     The Company uses the two-class method to compute basic and diluted EPS for all periods presented. The following illustrates the earnings allocation method utilized in the calculation of basic and diluted EPS.

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(In millions, except per share amounts)
EPS numerator:
Income from continuing operations, net of income taxes	$	214.7		$	90.0		$	351.8		$	231.2
Less: Net income (loss) attributable to noncontrolling interests		8.0			2.8			11.0			8.0
Income from continuing operations attributable to common stockholders before allocation of earnings to participating securities		206.7			87.2			340.8			223.2
Less: Earnings allocated to participating securities		(1.5	)		(0.5	)		(2.5	)		(1.6	)
Income from continuing operations attributable to common stockholders (1)		205.2			86.7			338.3			221.6
Income (loss) from discontinued operations, net of income taxes		(0.5	)		(8.0	)		(0.9	)		26.0
Net income attributable to common stockholders (1)	$	204.7		$	78.7		$	337.4		$	247.6
Weighted average shares outstanding — basic		266.6			265.3			266.6			265.3
Dilutive impact of share-based compensation		1.7			1.8			1.7			1.8
Weighted average shares outstanding — diluted (2)		268.3			267.1			268.3			267.1
Basic EPS attributable to common stockholders:
Income from continuing operations	$	0.77		$	0.33		$	1.27		$	0.83
Income (loss) from discontinued operations		—			(0.03	)		—			0.10
Net income	$	0.77		$	0.30		$	1.27		$	0.93
Diluted EPS attributable to common stockholders:
Income from continuing operations	$	0.76		$	0.32		$	1.26		$	0.83
Income (loss) from discontinued operations		—			(0.03	)		—			0.10
Net income	$	0.76		$	0.29		$	1.26		$	0.93

(1)	The reallocation adjustment for participating securities to arrive at the numerator used to calculate diluted EPS was less than $0.1 million for the periods presented.
(2)	Weighted average shares outstanding excludes anti-dilutive shares that were less than 0.1 million for the three and six months ended June 30, 2010 and 0.2 million for the three months ended June 30, 2009 and 0.4 million for the six months ended June 30, 2009.

(10) Pension and Postretirement Benefit Costs

     Net periodic pension costs included the following components:

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(Dollars in millions)
Service cost for benefits earned	$	0.4		$	0.3		$	0.8		$	0.7
Interest cost on projected benefit obligation		12.6			12.8			25.2			25.6
Expected return on plan assets		(15.0	)		(15.2	)		(29.2	)		(30.4	)
Amortization of prior service cost and actuarial loss		5.9			0.9			11.7			1.7
Net periodic pension costs (benefit)	$	3.9		$	(1.2	)	$	8.5		$	(2.4	)

10

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     Net periodic postretirement benefit costs included the following components:

	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
	(Dollars in millions)
Service cost for benefits earned	$	3.1	$	2.5	$	6.2	$	5.2
Interest cost on accumulated postretirement benefit obligation		14.6		13.5		29.1		27.5
Amortization of prior service cost and actuarial loss		6.8		3.5		13.7		7.8
Net periodic postretirement benefit costs	$	24.5	$	19.5	$	49.0	$	40.5

     During the six months ended June 30, 2010, the Company made discretionary contributions of approximately $19 million to its defined benefit pension plans. The Company expects to make additional discretionary contributions to such plans of approximately $6 million during 2010. Total minimum and discretionary contributions in 2010 are expected to be approximately $28 million.

     In March 2010, President Obama signed into law comprehensive health care reform legislation under the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 (the Acts). Based on the Company’s analyses to date, it does not currently believe the Acts will result in a remeasurement of the Company’s postretirement health care liabilities, but will continue to assess the accounting implications of the Acts as related regulations and interpretations of the Acts become available. The extent of the impact cannot be actuarially determined until related regulations are promulgated and additional interpretations of the Acts become available. Provisions within the Acts for which financial impacts to the Company’s postretirement health care liabilities are possible, but not currently determinable, include application of the excise tax on high-cost employer coverage. The Company does not expect the other provisions of the Acts to materially impact its postretirement health care liabilities or results of operations. The Acts also impact active employees through various changes and/or expansions of healthcare benefits and coverage. While the Company will continue to monitor and assess the effect of the Acts on its active employee population, the Company cannot reasonably predict at this time what the amount of any additional cost may be.

(11) Segment Information

     The Company reports its operations primarily through the following reportable operating segments: “Western U.S. Mining,” “Midwestern U.S. Mining,” “Australian Mining,” “Trading and Brokerage” and “Corporate and Other.” The Company’s chief operating decision maker uses Adjusted EBITDA as the primary measure of segment profit and loss. The Company defines Adjusted EBITDA as income from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expense and depreciation, depletion and amortization.

11

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     Operating segment results for the three and six months ended June 30, 2010 and 2009 were as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	(Dollars in millions)
Revenues:
Western U.S. Mining	$	652.1		$	635.4		$	1,314.2		$	1,289.2
Midwestern U.S. Mining		323.3			339.8			632.7			650.5
Australian Mining		597.4			309.0			1,043.9			669.3
Trading and Brokerage		81.8			48.4			171.9			171.9
Corporate and Other		6.8			5.6			14.3			10.3
Total	$	1,661.4		$	1,338.2		$	3,177.0		$	2,791.2
Adjusted EBITDA:
Western U.S. Mining	$	207.3		$	152.1		$	415.2		$	335.3
Midwestern U.S. Mining		71.4			73.3			145.5			140.4
Australian Mining		223.6			127.7			346.9			210.9
Trading and Brokerage		14.3			35.5			46.7			101.0
Corporate and Other		(76.2	)		(62.4	)		(156.7	)		(136.0	)
Total	$	440.4		$	326.2		$	797.6		$	651.6

     A reconciliation of adjusted EBITDA to consolidated income from continuing operations follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	(Dollars in millions)
Total Adjusted EBITDA	$	440.4		$	326.2		$	797.6		$	651.6
Depreciation, depletion and amortization		105.1			101.2			210.6			197.5
Asset retirement obligation expense		10.9			9.6			20.4			19.0
Interest expense		57.9			48.2			107.9			99.3
Interest income		(1.6	)		(1.2	)		(2.6	)		(4.0	)
Income tax provision		53.4			78.4			109.5			108.6
Income from continuing operations, net of income taxes	$	214.7		$	90.0		$	351.8		$	231.2

(12) Risk Management and Fair Value Measurements

Risk Management — Non Coal Trading

     The Company is exposed to various types of risk in the normal course of business, including fluctuations in commodity prices, interest rates and foreign currency exchange rates. These risks are actively monitored in an effort to ensure compliance with the risk management policies of the Company. In most cases, commodity price risk (excluding coal trading activities) related to the sale of coal is mitigated through the use of long-term, fixed-price contracts rather than financial instruments.

12

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     Interest Rate Swaps. The Company is exposed to interest rate risk on its fixed rate and variable rate long-term debt. From time to time, the Company manages the interest rate risk associated with the fair value of its fixed rate borrowings using fixed-to-floating interest rate swaps to effectively convert a portion of the underlying cash flows on the debt into variable rate cash flows. The Company designates these swaps as fair value hedges, with the objective of hedging against changes in the fair value of the fixed rate debt that result from market interest rate changes. From time to time, the interest rate risk associated with the Company’s variable rate borrowings is managed using floating-to-fixed interest rate swaps. The Company designates these swaps as cash flow hedges, with the objective of reducing the variability of cash flows associated with market interest rate changes. As of June 30, 2010, the Company had no interest rate swaps in place.

     Foreign Currency Hedges. The Company is exposed to foreign currency exchange rate risk on Australian dollar expenditures made in its Australian Mining segment. This risk is managed by entering into forward contracts and options that the Company designates as cash flow hedges, with the objective of reducing the variability of cash flows associated with forecasted Australian dollar expenditures. As of June 30, 2010, the Company had only forward contracts in place.

     Diesel Fuel and Explosives Hedges. The Company is exposed to commodity price risk associated with diesel fuel in the U.S. and Australia and explosives in the U.S. Explosives costs, and a portion of the diesel fuel costs, in Australia are included in the fees paid to the Company’s contract miners. This risk is managed through the use of fixed price contracts, cost plus contracts and derivatives, primarily swaps. The Company has generally designated the swap contracts as cash flow hedges, with the objective of reducing the variability of cash flows associated with the forecasted purchase of diesel fuel and explosives.

     Notional Amounts and Fair Value. The following summarizes the Company’s foreign currency and commodity positions at June 30, 2010:

	Notional Amount by Year of Maturity
													2015 and
	Total		2010		2011		2012		2013		2014		thereafter
Foreign Currency
A$:US$ hedge contracts (A$ millions)	$	4,592.7	$	837.2	$	1,365.2	$	1,279.2	$	689.6	$	421.5	$	—
Commodity Contracts
Diesel fuel hedge contracts (million gallons)		218.1		42.5		88.7		68.3		18.6		—		—
U.S. explosives hedge contracts (million MMBtu)		1.5		1.5		—		—		—		—		—

	Account Classification by
	Cash flow		Fair value		Economic		Fair Value Asset
	hedge		hedge		hedge		(Liability)
							(Dollars in millions)
Foreign Currency
A$:US$ hedge contracts (A$ millions)	$	4,592.7	$	—	$	—	$	60.8
Commodity Contracts
Diesel fuel hedge contracts (million gallons)		218.1		—		—	$	(34.9	)
U.S. explosives hedge contracts (million MMBtu)		1.5		—		—	$	(3.5	)

13

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     Hedge Ineffectiveness. The Company assesses both at inception and at least quarterly thereafter, whether the derivatives used in hedging activities are highly effective at offsetting the changes in the anticipated cash flows of the hedged item. The effective portion of the change in the fair value is recorded as a separate component of stockholders’ equity until the hedged transaction impacts reported earnings, at which time gains and losses are reclassified to the consolidated statements of operations at the time of the recognition of the underlying hedged item. The ineffective portion of the derivative’s change in fair value is recorded in the consolidated statements of operations. In addition, if the hedging relationship ceases to be highly effective, or it becomes probable that a forecasted transaction is no longer expected to occur, gains and losses on the derivative are recorded to the consolidated statements of operations.

     A measure of ineffectiveness is inherent in hedging future diesel fuel purchases with derivative positions based on crude oil and refined petroleum products.

     The Company’s hedging of future explosives purchases also has an inherent measure of ineffectiveness as the derivative positions are primarily based on natural gas which closely matches the contractual purchase price of explosives since price changes occur in a constant ratio of MMBtu per ton in the manufacture of explosives and generally carry a fixed surcharge.

     With respect to the interest rate swaps, there was no hedge ineffectiveness recognized in the unaudited condensed consolidated statements of operations during the three or six months ended June 30, 2010 and 2009.

     The tables below show the classification and amounts of pre-tax gains and losses related to the Company’s non-trading hedges during the three and six months ended June 30, 2010 and 2009:

		Three Months Ended June 30, 2010
		Gain (loss)			Gain (loss)			Gain (loss)			Gain (loss) reclassified
		recognized in			recognized in other			reclassified from			from other
		income on non			comprehensive			other comprehensive			comprehensive income
	Income Statement Classification	designated			income on derivative			income into income			into income
Financial Instrument	Gains (Losses) - Realized	derivatives(1)			(effective portion)			(effective portion)			(ineffective portion)
		(Dollars in millions)
Interest rate swaps:
- Cash flow hedges	Interest expense	$	(8.5	)	$	(0.1	)	$	0.7		$	—
Diesel fuel hedge contracts:
- Cash flow hedges	Operating costs and expenses		—			(40.2	)		(9.3	)		(1.7	)
Explosives cash flow hedge contracts:
- Cash flow hedges	Operating costs and expenses		—			0.2			(2.6	)		—
Foreign currency cash flow hedge contracts	Operating costs and expenses		—			(161.4	)		27.1			—
Total		$	(8.5	)	$	(201.5	)	$	15.9		$	(1.7	)

⁽¹⁾ Amounts relate to swaps that were de-designated and terminated in conjunction with the refinancing of the Company’s previous credit facility.

14

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

		Three Months Ended June 30, 2009
		Gain (loss)		Gain (loss)			Gain (loss)			Gain (loss) reclassified
		recognized in		recognized in other			reclassified from			from other
		income on non		comprehensive			other comprehensive			comprehensive income
	Income Statement Classification	designated		income on derivative			income into income			into income
Financial Instrument	Gains (Losses) - Realized	derivatives(2)		(effective portion)			(effective portion)			(ineffective portion)
		(Dollars in millions)
Interest rate swaps:
- Cash flow hedges	Interest expense	$	—	$	(1.0	)	$	(3.3	)	$	—
Diesel fuel hedge contracts:
- Cash flow hedges	Operating costs and expenses		—		51.8			(23.2	)		2.1
- Economic hedges	Operating costs and expenses		1.3		—			—			—
Explosives cash flow hedge contracts:
- Cash flow hedges	Operating costs and expenses		—		1.7			(4.8	)		—
- Economic hedges	Operating costs and expenses		1.2		—			—			—
Foreign currency cash flow hedge contracts	Operating costs and expenses		—		260.1			(15.4	)		—
Total		$	2.5	$	312.6		$	(46.7	)	$	2.1

⁽²⁾ Amounts relate to derivatives that were de-designated and settled in 2009.

		Six Months Ended June 30, 2010
		Gain (loss)			Gain (loss)			Gain (loss)			Gain (loss) reclassified
		recognized in			recognized in other			reclassified from			from other
		income on non			comprehensive			other comprehensive			comprehensive income
	Income Statement Classification	designated			income on derivative			income into income			into income
Financial Instrument	Gains (Losses) - Realized	derivatives(1)			(effective portion)			(effective portion)			(ineffective portion)
		(Dollars in millions)
Interest rate swaps:
- Cash flow hedges	Interest expense	$	(8.5	)	$	0.8		$	(0.5	)	$	—
Diesel fuel hedge contracts:
- Cash flow hedges	Operating costs and expenses		—			(29.8	)		(16.4	)		(0.7	)
Explosives cash flow hedge contracts:
- Cash flow hedges	Operating costs and expenses		—			(3.6	)		(4.9	)		—
Foreign currency cash flow hedge contracts	Operating costs and expenses		—			(79.4	)		65.9			—
Total		$	(8.5	)	$	(112.0	)	$	44.1		$	(0.7	)

⁽¹⁾ Amounts relate to swaps that were de-designated and terminated in conjunction with the refinancing of the Company’s previous credit facility.

		Six Months Ended June 30, 2009
		Gain (loss)			Gain (loss)			Gain (loss)			Gain (loss) reclassified
		recognized in			recognized in other			reclassified from			from other
		income on non			comprehensive			other comprehensive			comprehensive income
	Income Statement Classification	designated			income on derivative			income into income			into income
Financial Instrument	Gains (Losses) - Realized	derivatives(2)			(effective portion)			(effective portion)			(ineffective portion)
		(Dollars in millions)
Interest rate swaps:
- Cash flow hedges	Interest expense	$	—		$	0.1		$	(6.3	)	$	—
Diesel fuel hedge contracts:
- Cash flow hedges	Operating costs and expenses		—			41.3			(52.7	)		0.2
- Economic hedges	Operating costs and expenses		(0.7	)		—			—			—
Explosives cash flow hedge contracts:
- Cash flow hedges	Operating costs and expenses		—			(4.2	)		(10.3	)		—
- Economic hedges	Operating costs and expenses		(0.8	)		—			—			—
Foreign currency cash flow hedge contracts	Operating costs and expenses		—			250.5			(59.6	)		—
Total		$	(1.5	)	$	287.7		$	(128.9	)	$	0.2

⁽²⁾ Amounts relate to derivatives that were de-designated and settled in 2009.

15

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     The classification and amount of derivatives presented on a gross basis as of June 30, 2010 and December 31, 2009 are as follows:

	Fair Value as of June 30, 2010
	Current		Noncurrent		Current		Noncurrent
Financial Instrument	Assets		Assets		Liabilities		Liabilities
	(Dollars in millions)
Diesel fuel cash flow hedge contracts	$	3.5	$	4.6	$	30.0	$	13.0
Explosives cash flow hedge contracts		—		—		3.5		—
Foreign currency cash flow hedge contracts		61.0		65.0		21.1		44.1
Total	$	64.5	$	69.6	$	54.6	$	57.1

	Fair Value as of December 31, 2009
	Current		Noncurrent		Current		Noncurrent
Financial Instrument	Assets		Assets		Liabilities		Liabilities
	(Dollars in millions)
Interest rate swaps:
- Fair value hedges	$	—	$	1.5	$	—	$	—
- Cash flow hedges		—		—		—		9.8
Diesel fuel cash flow hedge contracts		6.7		18.0		31.3		15.6
Explosives cash flow hedge contracts		0.1		—		4.9		—
Foreign currency cash flow hedge contracts		110.6		100.2		1.6		3.1
Total	$	117.4	$	119.7	$	37.8	$	28.5

     After netting by counterparty where permitted, the fair values of the respective derivatives are reflected in “Other current assets,” “Investments and other assets,” “Accounts payable and accrued expenses,” and “Other noncurrent liabilities” in the condensed consolidated balance sheets.

     The Company elected the trading exemption under U.S. generally accepted accounting principles (GAAP) for its coal trading transactions which allows for reduced disclosure since it is the Company’s policy to include these instruments as a part of its trading book. For further information, see Risk Management — Coal Trading below.

Risk Management — Coal Trading

     The Company engages in trading activities which include over-the-counter direct and brokered trading of coal and the related ocean freight along with the related fuel commodities (coal trading), some of which is subsequently exchange-cleared and some of which is bilaterally-cleared. Except those for which the Company has elected to apply a normal purchases and normal sales exception, derivative coal trading contracts are accounted for on a fair value basis. For derivative trading contracts, the Company establishes fair values using bid/ask price quotations or other market assessments obtained from multiple, independent third-party brokers to value its trading positions from the over-the-counter market. Prices from these sources are then averaged to obtain trading position values. While the Company does not anticipate any decrease in the number of third-party brokers or market liquidity, such events could erode the quality of market information and therefore negatively impact the Company’s ability to value its market positions. For its exchange-cleared positions, the Company utilizes exchange-published settlement prices. See Note 4 for information related to the maturity and valuation of the Company’s trading portfolio.

16

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     Trading revenues are recorded in “Other revenues” in the unaudited condensed consolidated statements of operations and include realized and unrealized gains and losses on derivative instruments, including those under the normal purchases and normal sales exception. The tables below show the trading revenues during the three and six months ended June 30, 2010 and 2009:

	Three Months Ended June 30,					Six Months Ended June 30,
Trading Revenue by Type of Instrument	2010			2009		2010			2009
	(Dollars in millions)
Commodity swaps and options	$	(36.8	)	$	29.0	$	(9.4	)	$	86.0
Physical commodity purchase / sale contracts		89.7			5.1		118.3			57.4
Total trading revenue	$	52.9		$	34.1	$	108.9		$	143.4

     Hedge Ineffectiveness. In some instances, the Company has designated an existing coal trading derivative as a hedge and, thus, the derivative has a non-zero fair value at hedge inception. The “off-market” nature of these derivatives, which is best described as an embedded financing element within the derivative, is a source of ineffectiveness. In other instances, the Company uses a coal trading derivative that settles at a different time or has a different location basis than the occurrence of the cash flow being hedged. The time and location basis differences yield ineffectiveness to the extent the periodic changes in the fair value of the derivatives exceed the changes in the hedged item. The ineffective portion of the derivative’s change in fair value is recorded in the consolidated statements of operations.

Nonperformance and Credit Risk

     The fair value of the Company’s assets and liabilities reflects adjustments for nonperformance and credit risk. The concentration of nonperformance and credit risk is substantially with electric utilities, energy producers and energy marketers. The Company’s policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to regularly monitor the credit extended. If the Company engages in a transaction with a counterparty that does not meet its credit standards, the Company seeks to protect its position by requiring the counterparty to provide an appropriate credit enhancement. Also, when appropriate (as determined by its credit management function), the Company has taken steps to reduce its exposure to customers or counterparties whose credit has deteriorated and who may pose a higher risk of failure to perform under their contractual obligations. These steps include obtaining letters of credit or cash collateral (margin), requiring prepayments for shipments or the creation of customer trust accounts held for the Company’s benefit to serve as collateral in the event of a failure to pay or perform. To reduce its credit exposure related to trading and brokerage activities, the Company seeks to enter into netting agreements with counterparties that permit the Company to offset receivables and payables with such counterparties and, to the extent required, will post or receive margin amounts associated with exchange-cleared positions.

     The Company conducts its hedging activities related to foreign currency, interest rate, and fuel and explosives exposures with a variety of highly-rated commercial banks and closely monitors counterparty creditworthiness.

     Certain of the Company’s derivative trading instruments require the parties to provide additional performance assurances whenever a material adverse event jeopardizes one party’s ability to perform under the instrument. In the event the Company were to sustain a material adverse event (using commercially reasonable standards), the counterparties could request collateralization on derivative trading instruments in net liability positions which, based on an aggregate fair value at June 30, 2010 and December 31, 2009, would have amounted to collateral postings of approximately $80 million for both periods to its counterparties.

17

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     Certain of the Company’s other derivative trading instruments require the parties to provide additional performance assurances whenever a credit downgrade occurs below a certain level as specified in each underlying contract. The terms of such derivative trading instruments typically require additional collateralization, which is commensurate with the severity of the credit downgrade. If a credit downgrade were to occur below contractually specified levels, the Company’s additional collateral requirements owed to its counterparties were estimated to be approximately $8 million at June 30, 2010 and approximately $16 million at December 31, 2009 based on the aggregate fair value of all derivative trading instruments with such features that are in a net liability position. No collateral was posted as of June 30, 2010 while $0.8 million was posted at December 31, 2009.

     The Company is required to post collateral on its exchange-settled positions for its entire net liability position, which was $9.8 million as of June 30, 2010 and $18.1 million as of December 31, 2009. In addition, the Company had posted $24.6 million and $29.7 million of collateral to meet the requirements of the respective exchanges at June 30, 2010 and December 31, 2009, respectively (reflected in “Other current assets”).

Fair Value Measurements

     The Company uses a three-level fair value hierarchy that categorizes assets and liabilities measured at fair value based on the observability of the inputs utilized in the valuation. These levels include: Level 1, inputs are quoted prices in active markets for the identical assets or liabilities; Level 2, inputs other than quoted prices included in Level 1 that are directly or indirectly observable through market-corroborated inputs; and Level 3, inputs are unobservable, or observable but cannot be market-corroborated, requiring the Company to make assumptions about pricing by market participants.

     The following tables set forth the hierarchy of the Company’s net financial asset (liability) positions for which fair value is measured on a recurring basis:

	June 30, 2010
	Level 1		Level 2			Level 3		Total
	(Dollars in millions)
Commodity swaps and options — coal trading activities	$	3.5	$	45.4		$	—	$	48.9
Commodity swaps and options — diesel fuel		—		(34.9	)		—		(34.9	)
Commodity swaps and options — explosives		—		(3.5	)		—		(3.5	)
Physical commodity purchase/sale contracts — coal trading activities		—		55.2			13.8		69.0
Foreign currency hedge contracts		—		60.8			—		60.8
Total net financial assets	$	3.5	$	123.0		$	13.8	$	140.3

	December 31, 2009
	Level 1			Level 2			Level 3		Total
	(Dollars in millions)
Commodity swaps and options — coal trading activities	$	(1.7	)	$	80.7		$	—	$	79.0
Commodity swaps and options — diesel fuel		—			(22.2	)		—		(22.2	)
Commodity swaps and options — explosives		—			(4.8	)		—		(4.8	)
Physical commodity purchase/sale contracts — coal trading activities		—			70.2			17.0		87.2
Interest rate swaps		—			(8.3	)		—		(8.3	)
Foreign currency hedge contracts		—			206.1			—		206.1
Total net financial assets (liabilities)	$	(1.7	)	$	321.7		$	17.0	$	337.0

18

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     For Level 1 and 2 financial assets and liabilities, the Company utilizes both direct and indirect observable price quotes, including interest rate yield curves, exchange indices, broker quotes, published indices, and other market quotes. Below is a summary of the Company’s valuation techniques for Level 1 and 2 financial assets and liabilities:

• Commodity swaps and options — coal trading activities: generally valued based on unadjusted quoted prices in active markets (Level 1) or a valuation that is corroborated by the use of market-based pricing (Level 2).

• Commodity swaps and options — other than coal: generally valued based on a valuation that is corroborated by the use of market-based pricing (Level 2).

• Physical commodity purchase/sale contracts — coal trading activities: purchases and sales at locations with significant market activity corroborated by market-based information (Level 2).

• Interest rate swaps: valued based on modeling observable market data and corroborated with statements from counterparties (Level 2).

• Foreign currency hedge contracts: valued utilizing inputs obtained in quoted public markets (Level 2).

     Commodity swaps and options and physical commodity purchase/sale contracts transacted in less liquid markets or contracts, such as long-term arrangements with limited price availability were classified in Level 3. These instruments or contracts are valued based on quoted inputs from brokers or counterparties, or reflect methodologies that consider historical relationships among similar commodities to derive the Company’s best estimate of fair value. The Company has consistently applied these valuation techniques in all periods presented, and believes it has obtained the most accurate information available for the types of derivative contracts held.

     The Company did not have any transfers between Level 1 and Level 2 during the three or six months ended June 30, 2010. The Company’s policy is to value all transfers between levels using the beginning of period valuation. This represents a change in policy from those in effect at December 31, 2009. Previously, the end of the period values were used for transfers into Level 3 and beginning of period values for transfers out of Level 3.

     The following table summarizes the changes in the Company’s recurring Level 3 net financial assets (liabilities):

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(Dollars in millions)
Beginning of period	$	12.5		$	(3.6	)	$	17.0		$	37.8
Total gains or losses (realized/unrealized):
Included in earnings		3.3			11.7			(0.4	)		(9.1	)
Included in other comprehensive income		0.5			2.0			—			(11.5	)
Purchases, issuances and settlements		(2.5	)		(7.7	)		(2.8	)		(7.5	)
Transfers out		—			—			—			(7.3	)
End of period	$	13.8		$	2.4		$	13.8		$	2.4

19

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     The following table summarizes the changes in unrealized gains (losses) relating to Level 3 net financial assets still held at the end of the period:

	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
	(Dollars in millions)
Changes in unrealized gains (losses) (1)	$	2.2	$	7.2	$	1.3	$	(3.7	)

(1) Within the unaudited condensed consolidated statements of operations for the periods presented, unrealized gains and losses from Level 3 items are combined with unrealized gains and losses on positions classified in Level 1 or 2, as well as other positions that have been realized during the applicable periods.

Fair Value — Other Financial Instruments

     The following methods and assumptions were used by the Company in estimating fair values for other financial instruments as of June 30, 2010 and December 31, 2009:

• Cash and cash equivalents, accounts receivable, including accounts receivable within the Company’s securitization program, and accounts payable and accrued expenses have carrying values which approximate fair value due to the short maturity or the financial nature of these instruments.

• Long-term debt fair value estimates are based on observed prices for securities with an active trading market when available, and otherwise on estimated borrowing rates to discount the cash flows to their present value. The carrying amounts of the 7.875% Senior Notes due 2026 and the Convertible Junior Subordinated Debentures due 2066 are net of the respective unamortized note discounts.

     The carrying amounts and estimated fair values of the Company’s debt are summarized as follows:

	June 30, 2010				December 31, 2009
	Carrying		Estimated		Carrying		Estimated
	Amount		Fair Value		Amount		Fair Value
	(Dollars in millions)
Long-term debt	$	2,762.8	$	2,826.5	$	2,752.3	$	2,828.8

(13) Commitments and Contingencies

Commitments

     As of June 30, 2010, purchase commitments for capital expenditures were $66.4 million.

     The Company controls a 17.7% interest in the Newcastle Coal Infrastructure Group (NCIG), which is developing a coal transloading facility in Newcastle, Australia. In the second quarter of 2010, stage one of construction was completed and the facility began shipping coal. The facility, which is backed by take or pay agreements, is expected to close on financing for the next stage of construction in August 2010. To cover a financing shortfall for stage two, the Company has committed to fund a pro-rata share of the financing along with the other NCIG shareholders. The Company’s share is estimated to be $61 million Australian dollars (approximately $52 million U.S. dollars).

     A subsidiary of the Company owns a 5.06% undivided interest in the Prairie State Energy Campus (Prairie State), a 1,600 megawatt coal-fuel electricity generation project currently under construction. The Company spent $30.5 million during the six months ended June 30, 2010 representing its 5.06% share of the construction costs. Included in “Investments and other assets” in the condensed consolidated balance sheets as of June 30, 2010 and December 31, 2009, are costs of $157.1 million and $126.6 million, respectively. The Company’s share of total construction costs for Prairie State is expected to be approximately $210 million.

20

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     The Company is an equity partner in GreenGen, a partnership to fund the construction in China of a near-zero emissions coal-fueled power plant with carbon capture and storage. During the six months ended June 30, 2010, the Company spent $3.1 million representing its 6.0% share of the construction costs, which is reflected as capitalized development costs as part of “Investments and other assets” in the condensed consolidated balance sheet. There were no expenditures for GreenGen for 2009. The Company’s share of total construction costs for GreenGen is expected to be approximately $60 million U.S. dollars.

Contingencies

     From time to time, the Company or its subsidiaries are involved in legal proceedings arising in the ordinary course of business or related to indemnities or historical operations. The Company believes it has recorded adequate reserves for these liabilities and that there is no individual case pending that is likely to have a material adverse effect on the Company’s financial condition, results of operations or cash flows. The Company discusses its significant legal proceedings below.

Litigation Relating to Continuing Operations

     Navajo Nation Litigation. On June 18, 1999, the Navajo Nation served three of the Company’s subsidiaries, including Peabody Western Coal Company (Peabody Western), with a complaint that had been filed in the U.S. District Court for the District of Columbia. The Navajo Nation alleged 16 claims, including Civil Racketeer Influenced and Corrupt Organizations Act (RICO) violations and fraud. On April 12, 2010, the Navajo Nation filed an amended complaint to substantially narrow the scope of the Navajo Nation’s claims by removing the RICO allegations but leaving the other 12 common law tort and contractual claims. The complaint alleges that the defendants jointly participated in unlawful activity to obtain favorable coal lease amendments. The plaintiff is seeking various remedies including actual damages of at least $600 million, punitive damages of at least $1 billion, a determination that Peabody Western’s two coal leases terminated due to Peabody Western’s breach of these leases and a reformation of these leases to adjust the royalty rate to 20%. The court has allowed the Hopi Tribe to intervene in this lawsuit and the Hopi Tribe is also seeking unspecified actual damages, punitive damages and reformation of its coal lease. One of the Company’s subsidiaries named as a defendant is now a subsidiary of Patriot. However, the Company is responsible for this litigation under the Separation Agreement entered into with Patriot in connection with the spin-off. The U.S. Supreme Court has ruled against the Navajo Nation in a related case against the U.S. government, and remanded that case to the lower court to dismiss the complaint. The U.S. Supreme Court said that none of the sources relied on by the Navajo Nation provided a basis for its breach-of-trust lawsuit against the U.S. government, which undermines some of the claims the Navajo Nation asserts in its litigation against the Company.

     The outcome of this litigation is subject to numerous uncertainties. Based on the Company’s evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably estimated. However, based on current information, the Company believes this matter is likely to be resolved without a material adverse effect on the Company’s financial condition, results of operations or cash flows.

     Gulf Power Company Litigation. On June 22, 2006, Gulf Power Company (Gulf Power) filed a breach of contract lawsuit against a Company subsidiary in the U.S. District Court, Northern District of Florida, contesting the force majeure declaration by the Company’s subsidiary under a coal supply agreement with Gulf Power and seeking damages for alleged past and future tonnage shortfalls of nearly 5 million tons under the agreement, which expired on December 31, 2007. In February 2008, the court denied the Company’s motion to dismiss the Florida lawsuit or to transfer it to Illinois and retained jurisdiction over the case. Gulf Power filed a motion for partial summary judgment on liability, and the Company subsidiary filed a motion for summary judgment seeking complete dismissal. On September 30, 2009, the court granted Gulf Power’s motion for partial summary judgment and denied the Company subsidiary’s motion for summary judgment. In October 2009, the Company’s subsidiary filed a motion for reconsideration which the court denied. The damages portion of the trial was held in February 2010; however, the court has not yet rendered its decision in the case.

     The outcome of this litigation is subject to numerous uncertainties. Based on the Company’s evaluation of the issues and their potential impact, the amount of any future loss cannot reasonably be estimated. However, based on current information, the Company believes this matter is likely to be resolved without a material adverse effect on its financial condition, results of operations or cash flows.

21

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Claims and Litigation Relating to Indemnities or Historical Operations

     Oklahoma Lead Litigation. Gold Fields Mining, LLC (Gold Fields) is a dormant, non-coal producing entity that was previously managed and owned by Hanson PLC, the Company’s predecessor owner. In a February 1997 spin-off, Hanson PLC transferred ownership of Gold Fields to the Company, despite the fact that Gold Fields had no ongoing operations and the Company had no prior involvement in its past operations. Gold Fields is currently one of the Company’s subsidiaries. The Company indemnified TXU Group with respect to certain claims relating to a former affiliate of Gold Fields. A predecessor of Gold Fields formerly operated two lead mills near Picher, Oklahoma prior to the 1950s and mined, in accordance with lease agreements and permits, approximately 0.15% of the total amount of the crude ore mined in the county.

     Gold Fields and several other companies are defendants in two property damage lawsuits arising from past operations near Picher, Oklahoma. The plaintiffs are seeking compensatory damages for diminution in property values and punitive damages. These cases were originally filed as putative class actions, but the court has denied class certification and the cases were subsequently amended to include a number of individual plaintiffs. In December 2003, the Quapaw Indian tribe and certain Quapaw land owners filed a lawsuit against Gold Fields, five other companies and the U.S. The plaintiffs are seeking compensatory and punitive damages based on a variety of theories. In December 2007, the court dismissed the tribe’s medical monitoring claim. In July 2008, the court dismissed the tribe’s claim for interim and lost use damages under the Comprehensive Environmental Response, Compensation and Liability Act without prejudice to refile at the point the U.S. Environmental Protection Agency (EPA) selects a final remedy for the site. Gold Fields has filed a third-party complaint against the U.S. and other parties. In February 2005, the state of Oklahoma on behalf of itself and several other parties sent a notice to Gold Fields and other companies regarding a possible natural resources damage claim. All of the lawsuits are pending in the U.S. District Court for the Northern District of Oklahoma.

     The outcome of litigation and these claims are subject to numerous uncertainties. Based on the Company’s evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably estimated. However, based on current information, the Company believes this matter is likely to be resolved without a material adverse effect on its financial condition, results of operations or cash flows.

Environmental Claims and Litigation

     Environmental claims have been asserted against Gold Fields related to activities of Gold Fields or a former affiliate. Gold Fields or the former affiliate has been named a potentially responsible party (PRP) at five national priority list sites based on the Superfund Amendments and Reauthorization Act of 1986. Claims were asserted at 12 additional sites, bringing the total to 17, which have since been reduced to 10 by completion of work, transfer or regulatory inactivity. The number of PRP sites in and of itself is not a relevant measure of liability, because the nature and extent of environmental concerns varies by site, as does the estimated share of responsibility for Gold Fields or the former affiliate. Undiscounted liabilities for environmental cleanup-related costs for all of the sites noted above were $47.2 million as of June 30, 2010 and $49.5 million as of December 31, 2009, $5.6 million and $7.9 million of which was reflected as a current liability, respectively. These amounts represent those costs that the Company believes are probable and reasonably estimable. In September 2005, Gold Fields and other PRPs received a letter from the U.S. Department of Justice alleging that the PRP’s mining operations caused the EPA to incur approximately $125 million in residential yard remediation costs at Picher, Oklahoma and will cause the EPA to incur additional remediation costs relating to historical mining sites. In September 2008, Gold Fields and other PRPs received letters from the U.S. Department of Justice and the EPA re-initiating settlement negotiations. Gold Fields continues to participate in the settlement discussions. Gold Fields believes it has meritorious defenses to these claims.

     Gold Fields is involved in other litigation in the Picher area, and the Company indemnified TXU Group with respect to a defendant as is more fully discussed under the “Oklahoma Lead Litigation” caption above. Gold Fields has also been contacted by the state of Kansas (Kansas Department of Health and Environment) and is in negotiations for final resolution of natural resource damages claims at two sites. Significant uncertainty exists as to whether claims will be pursued against Gold Fields in all cases, and where they are pursued, the amount of the eventual costs and liabilities, which could be greater or less than the liabilities recorded in the condensed consolidated balance sheets. Based on the Company’s evaluation of the issues and their potential impact, the total amount of any future loss cannot be reasonably estimated. However, based on current information, the Company believes these claims and litigation are likely to be resolved without a material adverse effect on its financial condition, results of operations or cash flows.

22

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     Comer, et al v. Murphy Oil Co., et al. In April 2006, residents and owners of land and property along the Mississippi Gulf coast filed a purported class action lawsuit in the U.S. District Court in the Southern District of Mississippi against more than 45 oil, chemical, utility and coal companies, including the Company. The plaintiffs alleged that defendants’ greenhouse gas emissions “were a proximate and direct cause of the increase in the destructive capacity of Hurricane Katrina,” and sought damages based on several legal theories. The defendants filed motions to dismiss on the grounds of lack of personal and subject matter jurisdiction. In August 2007, the court granted defendants’ motion to dismiss for lack of subject matter jurisdiction finding that plaintiffs’ claims are barred by the political question doctrine and for lack of standing. In October 2009, a three-judge panel of the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit) reversed in part the decision of the trial court, holding that the plaintiffs had standing to assert their public and private nuisance, trespass and negligence claims. The court held that plaintiffs did not satisfy the prudential standing requirement for their unjust enrichment, fraudulent misrepresentation and civil conspiracy claims and dismissed those claims and ordered that the case be remanded to the district court for further proceedings. In March 2010, the Fifth Circuit vacated the panel opinion and ordered a hearing en banc before the full Fifth Circuit to consider plaintiffs’ appeal. After the en banc court was properly constituted, a recusal by one of the judges resulted in the en banc court losing its quorum. On May 28, 2010, the Fifth Circuit issued an order indicating that the court had no authority to reinstate the panel decision and directing the clerk to dismiss the appeal. The Company believes that this lawsuit is without merit and intends to defend against and oppose it vigorously, but cannot predict its outcome. Based on the Company’s evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably estimated. However, based on current information, the Company believes this matter is likely to be resolved without a material adverse effect on its financial condition, results of operations or cash flows.

     Native Village of Kivalina and City of Kivalina v. ExxonMobil Corporation, et al. In February 2008, the Native Village of Kivalina and the City of Kivalina filed a lawsuit in the U.S. District Court for the Northern District of California against the Company, several owners of electricity generating facilities and several oil companies. The plaintiffs are the governing bodies of a village in Alaska that they contend is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for nuisance, and allege that the defendants have acted in concert and are jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village. The defendants filed motions to dismiss on the grounds of lack of personal and subject matter jurisdiction. In September 2009, the court granted defendants’ motion to dismiss for lack of subject matter jurisdiction finding that plaintiffs’ federal claim for nuisance is barred by the political question doctrine and for lack of standing. The plaintiffs are appealing the court’s dismissal to the U.S. Court of Appeals for the Ninth Circuit. The plaintiffs and the defendants have filed their briefs, with the plaintiffs’ reply briefs due September 15, 2010.

Other

     In addition, at times the Company becomes a party to other claims, lawsuits, arbitration proceedings and administrative procedures in the ordinary course of business in the U.S., Australia and other countries where the Company does business. Based on current information, the Company believes that the ultimate resolution of such other pending or threatened proceedings is not reasonably likely to have a material adverse effect on its financial position, results of operations or liquidity.

     New York Office of the Attorney General Subpoena. The New York Office of the Attorney General sent a letter to the Company dated September 14, 2007 that referred to the Company’s “plans to build new coal-fired electric generating units,” and said that the “increase in CO₂ emissions from the operation of these units, in combination with Peabody Energy’s other coal-fired power plants, will subject Peabody Energy to increased financial, regulatory, and litigation risks.” The Company currently has no electricity generating capacity in place. The letter included a subpoena issued under New York state law, which seeks information and documents relating to the Company’s analysis of the risks associated with climate change and possible climate change legislation or regulations, and its disclosure of such risks to investors. The Company believes that it has made full and proper disclosure of these potential risks.

23

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(14) Guarantees and Financial Instruments with Off-Balance-Sheet Risk

     In the normal course of business, the Company is a party to guarantees and financial instruments with off-balance-sheet risk, such as bank letters of credit, performance or surety bonds and other guarantees and indemnities, which are not reflected in the accompanying condensed consolidated balance sheets. Such financial instruments are valued based on the amount of exposure under the instrument and the likelihood of required performance. In the Company’s past experience, virtually no claims have been made against these financial instruments. Management does not expect any material losses to result from these guarantees or off-balance-sheet instruments.

Letters of Credit and Bonding

     The Company has letters of credit, bank guarantees, surety bonds and corporate guarantees (such as self bonds) in support of the Company’s reclamation, coal lease obligations, and workers’ compensation as follows as of June 30, 2010:

					Workers’
	Reclamation		Lease		Compensation
	Obligations		Obligations		Obligations		Other (1)		Total
	(Dollars in millions)
Self bonding	$	888.9	$	—	$	—	$	—	$	888.9
Surety bonds		590.0		108.3		7.3		9.2		714.8
Bank guarantees		124.7		11.7		—		51.6		188.0
Letters of credit		0.1		—		40.2		203.6		243.9
	$	1,603.7	$	120.0	$	47.5	$	264.4	$	2,035.6

⁽¹⁾ Other includes letters of credit obligations described below and an additional $63.6 million in letters of credit and surety bonds related to collateral for surety companies, road maintenance, performance guarantees and other operations.

     The Company owns a 37.5% interest in Dominion Terminal Associates, a partnership that operates a coal export terminal in Newport News, Virginia under a 30-year lease that permits the partnership to purchase the terminal at the end of the lease term for a nominal amount. The partners have severally (but not jointly) agreed to make payments under various agreements which in the aggregate provide the partnership with sufficient funds to pay rents and to cover the principal and interest payments on the floating-rate industrial revenue bonds issued by the Peninsula Ports Authority, and which are supported by letters of credit from a commercial bank. As of June 30, 2010, the Company’s maximum reimbursement obligation to the commercial bank was in turn supported by four letters of credit totaling $42.7 million.

     The Company is party to an agreement with the Pension Benefit Guaranty Corporation (PBGC) and TXU Europe Limited, an affiliate of the Company’s former parent corporation, under which the Company is required to make special contributions to two of the Company’s defined benefit pension plans and to maintain a $37.0 million letter of credit in favor of the PBGC. If the Company or the PBGC gives notice of an intent to terminate one or more of the covered pension plans in which liabilities are not fully funded, or if the Company fails to maintain the letter of credit, the PBGC may draw down on the letter of credit and use the proceeds to satisfy liabilities under the Employee Retirement Income Security Act of 1974, as amended. The PBGC, however, is required to first apply amounts received from a $110.0 million guarantee in place from TXU Europe Limited in favor of the PBGC before it draws on the Company’s letter of credit. On November 19, 2002 TXU Europe Limited was placed under the administration process in the United Kingdom (a process similar to bankruptcy proceedings in the U.S.) and continues under this process as of June 30, 2010. As a result of these proceedings, TXU Europe Limited may be liquidated or otherwise reorganized in such a way as to relieve it of its obligations under its guarantee.

     At June 30, 2010, the Company has a $121.1 million letter of credit issued with respect to certain reclamation and performance obligations related to some of the Company’s Australian mines.

24

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Other Guarantees

     The Company has a liability recorded of $52.3 million as of June 30, 2010 and December 31, 2009 related to reclamation and bonding commitments associated with the purchase of approximately 427 million tons of coal reserves and surface lands in the Illinois Basin in 2007.

     The Company is the lessee under numerous equipment and property leases. It is common in such commercial lease transactions for the Company, as the lessee, to agree to indemnify the lessor for the value of the property or equipment leased, should the property be damaged or lost during the course of the Company’s operations. The Company expects that losses with respect to leased property would be covered by insurance (subject to deductibles). The Company and certain of its subsidiaries have guaranteed other subsidiaries’ performance under their various lease obligations. Aside from indemnification of the lessor for the value of the property leased, the Company’s maximum potential obligations under its leases are equal to the respective future minimum lease payments, and the Company assumes that no amounts could be recovered from third parties.

     In connection with the development of Prairie State, each owner, including the Company’s subsidiary, has issued a guarantee for its proportionate share (5.06% for the Company) of obligations to pay its percentage of the construction costs under the Target Price Engineering, Procurement and Construction Agreement with Bechtel Power Corporation.

     The Company has provided financial guarantees under certain long-term debt agreements entered into by its subsidiaries, and substantially all of the Company’s subsidiaries provide financial guarantees under long-term debt agreements entered into by the Company. The maximum amounts payable under the Company’s debt agreements are equal to the respective principal and interest payments.

     Accounts Receivable Securitization. The Company has an accounts receivable securitization program (securitization program) through its wholly-owned, bankruptcy-remote subsidiary (Seller). Under the securitization program, beginning in 2010, the Company contributes, on a revolving basis, trade receivables of most of the Company’s U.S. subsidiaries to the Seller, which then sells the receivables in their entirety to a consortium of unaffiliated asset-backed commercial paper conduits (the Conduits). After the sale, the Company, as servicer of the assets, collect the receivables on behalf of the Conduits for a nominal servicing fee. The Company utilizes proceeds from the sale of its accounts receivable as an alternative to short-term borrowings under the Company’s Credit Facility, effectively managing its overall borrowing costs and providing an additional source for working capital. The securitization program was renewed in May 2009 and amended in December 2009 in order to qualify for sale accounting under a newly adopted accounting standard related to financial asset transfers. Prior to amending the securitization program, the Company sold senior undivided interests in certain of its accounts receivable and retained subordinated interests in those receivables. The current securitization program extends to May 2012, while the letter of credit commitment that supports the commercial paper facility underlying the securitization program must be renewed annually.

     The Seller is a separate legal entity whose assets are available first and foremost to satisfy the claims of its creditors. Of the receivables sold to the Conduits, a portion of the amount due to the Seller is deferred until the ultimate collection of the underlying receivables. During the six months ended June 30, 2010, the Company received total consideration of $2,199.3 million related to accounts receivable sold under the securitization program, including $726.1 million of cash up front from the sale of the receivables, an additional $1,377.5 million of cash upon the collection of the underlying receivables, and $95.7 million that had not been collected at June 30, 2010 and was recorded at fair value which approximates carrying value. The reduction in accounts receivable as a result of securitization activity with the Conduits was $216.4 million at June 30, 2010 and $254.6 million at December 31, 2009.

25

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     The securitization activity has been reflected in the unaudited condensed consolidated statements of cash flows as operating activity because both the cash received from the Conduits upon sale of receivables as well as the cash received from the Conduits upon the ultimate collection of receivables are not subject to significantly different risks given the short-term nature of the Company’s trade receivables. The Company recorded expense associated with securitization transactions of $0.5 million and $1.0 million for the three months ended June 30, 2010 and 2009, respectively and $1.2 million and $2.3 million for the six months ended June 30, 2010 and 2009, respectively.

(15) Supplemental Guarantor/Non-Guarantor Financial Information

     In accordance with the indentures governing the 6.875% Senior Notes due March 2013, the 5.875% Senior Notes due March 2016, the 7.375% Senior Notes due November 2016 and the 7.875% Senior Notes due November 2026 (collectively the Senior Notes), certain wholly-owned U.S. subsidiaries of the Company have fully and unconditionally guaranteed these Senior Notes, on a joint and several basis. Separate financial statements and other disclosures concerning the Guarantor Subsidiaries are not presented because management believes that such information is not material to the holders of the Senior Notes. The following historical financial statement information is provided for the Guarantor/Non-Guarantor Subsidiaries.

Unaudited Supplemental Condensed Consolidated Statements of Operations

	Three Months Ended June 30, 2010
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	960.5		$	887.3		$	(186.4	)	$	1,661.4
Costs and expenses
Operating costs and expenses		(12.6	)		693.5			680.2			(186.4	)		1,174.7
Depreciation, depletion and amortization		—			72.7			32.4			—			105.1
Asset retirement obligation expense		—			8.0			2.9			—			10.9
Selling and administrative expenses		8.4			41.9			3.8			—			54.1
Other operating (income) loss:
Net gain on disposal or exchange of assets		—			(1.2	)		(0.2	)		—			(1.4	)
(Income) loss from equity affiliates		(240.5	)		1.9			1.8			230.4			(6.4	)
Interest expense		57.5			12.7			3.8			(16.1	)		57.9
Interest income		(3.8	)		(5.5	)		(8.4	)		16.1			(1.6	)
Income from continuing operations before income taxes		191.0			136.5			171.0			(230.4	)		268.1
Income tax provision (benefit)		(15.2	)		39.0			29.6			—			53.4
Income from continuing operations, net of income taxes		206.2			97.5			141.4			(230.4	)		214.7
Loss from discontinued operations, net of income taxes		—			(0.5	)		—			—			(0.5	)
Net income		206.2			97.0			141.4			(230.4	)		214.2
Less: Net income attributable to noncontrolling interests		—			—			8.0			—			8.0
Net income attributable to common stockholders	$	206.2		$	97.0		$	133.4		$	(230.4	)	$	206.2

26

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Unaudited Supplemental Condensed Consolidated Statements of Operations

	Three Months Ended June 30, 2009
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	915.8		$	546.9		$	(124.5	)	$	1,338.2
Costs and expenses
Operating costs and expenses		43.5			661.6			389.3			(124.5	)		969.9
Depreciation, depletion and amortization		—			70.9			30.3			—			101.2
Asset retirement obligation expense		—			8.6			1.0			—			9.6
Selling and administrative expenses		6.9			29.3			9.4			—			45.6
Other operating (income) loss:
Net gain on disposal or exchange of assets		—			(4.1	)		(6.0	)		—			(10.1	)
(Income) loss from equity affiliates		(144.3	)		1.7			4.9			144.3			6.6
Interest expense		47.9			8.0			12.1			(19.8	)		48.2
Interest income		(3.8	)		(3.9	)		(13.3	)		19.8			(1.2	)
Income from continuing operations before income taxes		49.8			143.7			119.2			(144.3	)		168.4
Income tax provision (benefit)		(33.5	)		29.3			82.6			—			78.4
Income from continuing operations, net of income taxes		83.3			114.4			36.6			(144.3	)		90.0
Loss from discontinued operations, net of income taxes		(4.1	)		(1.7	)		(2.2	)		—			(8.0	)
Net income		79.2			112.7			34.4			(144.3	)		82.0
Less: Net income attributable to noncontrolling interests		—			—			2.8			—			2.8
Net income attributable to common stockholders	$	79.2		$	112.7		$	31.6		$	(144.3	)	$	79.2

27

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Unaudited Supplemental Condensed Consolidated Statements of Operations

	Six Months Ended June 30, 2010
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	2,064.0		$	1,485.2		$	(372.2	)	$	3,177.0
Costs and expenses
Operating costs and expenses		(40.9	)		1,522.3			1,174.2			(372.2	)		2,283.4
Depreciation, depletion and amortization		—			145.1			65.5			—			210.6
Asset retirement obligation expense		—			15.0			5.4			—			20.4
Selling and administrative expenses		17.5			86.5			5.5			—			109.5
Other operating (income) loss:
Net gain on disposal or exchange of assets		—			(8.5	)		(0.2	)		—			(8.7	)
(Income) loss from equity affiliates		(391.1	)		3.7			3.0			379.6			(4.8	)
Interest expense		107.0			25.5			7.5			(32.1	)		107.9
Interest income		(7.6	)		(10.9	)		(16.2	)		32.1			(2.6	)
Income from continuing operations before income taxes		315.1			285.3			240.5			(379.6	)		461.3
Income tax provision (benefit)		(24.8	)		87.9			46.4			—			109.5
Income from continuing operations, net of income taxes		339.9			197.4			194.1			(379.6	)		351.8
Loss from discontinued operations, net of income taxes		—			(0.9	)		—			—			(0.9	)
Net income		339.9			196.5			194.1			(379.6	)		350.9
Less: Net income attributable to noncontrolling interests		—			—			11.0			—			11.0
Net income attributable to common stockholders	$	339.9		$	196.5		$	183.1		$	(379.6	)	$	339.9

28

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Unaudited Supplemental Condensed Consolidated Statements of Operations

	Six Months Ended June 30, 2009
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	2,101.0		$	945.6		$	(255.4	)	$	2,791.2
Costs and expenses
Operating costs and expenses		122.9			1,580.5			602.6			(255.4	)		2,050.6
Depreciation, depletion and amortization		—			143.4			54.1			—			197.5
Asset retirement obligation expense		—			17.2			1.8			—			19.0
Selling and administrative expenses		14.1			65.7			11.9			—			91.7
Other operating (income) loss:
Net gain on disposal or exchange of assets		—			(7.4	)		(6.0	)		—			(13.4	)
(Income) loss from equity affiliates		(358.7	)		3.3			7.4			358.7			10.7
Interest expense		97.8			24.8			16.7			(40.0	)		99.3
Interest income		(7.7	)		(18.3	)		(18.0	)		40.0			(4.0	)
Income from continuing operations before income taxes		131.6			291.8			275.1			(358.7	)		339.8
Income tax provision (benefit)		(87.4	)		70.3			125.7			—			108.6
Income from continuing operations, net of income taxes		219.0			221.5			149.4			(358.7	)		231.2
Income (loss) from discontinued operations, net of income taxes		30.2			(1.2	)		(3.0	)		—			26.0
Net income		249.2			220.3			146.4			(358.7	)		257.2
Less: Net income attributable to noncontrolling interests		—			—			8.0			—			8.0
Net income attributable to common stockholders	$	249.2		$	220.3		$	138.4		$	(358.7	)	$	249.2

29

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Unaudited Supplemental Condensed Consolidated Balance Sheets

	June 30, 2010
	Parent		Guarantor			Non-Guarantor			Reclassifications/
	Company		Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Assets
Current assets
Cash and cash equivalents	$	449.0	$	0.2		$	707.8		$	—		$	1,157.0
Accounts receivable, net		0.7		27.0			366.0			—			393.7
Inventories		—		174.6			188.8			—			363.4
Assets from coal trading activities, net		—		53.2			144.6			—			197.8
Deferred income taxes		11.6		56.7			—			(11.0	)		57.3
Other current assets		60.8		32.7			67.5			—			161.0
Total current assets		522.1		344.4			1,474.7			(11.0	)		2,330.2
Property, plant, equipment and mine development
Land and coal interests		—		4,824.6			2,760.9			—			7,585.5
Buildings and improvements		—		843.3			128.9			—			972.2
Machinery and equipment		—		1,200.9			288.9			—			1,489.8
Less: accumulated depreciation, depletion and amortization		—		(2,236.2	)		(564.9	)		—			(2,801.1	)
Property, plant, equipment and mine development, net		—		4,632.6			2,613.8			—			7,246.4
Deferred income taxes		176.9		—			—			(176.9	)		—
Investments and other assets		9,281.2		161.2			31.0			(8,952.2	)		521.2
Total assets	$	9,980.2	$	5,138.2		$	4,119.5		$	(9,140.1	)	$	10,097.8
Liabilities and Stockholders’ Equity
Current liabilities
Current maturities of long-term debt	$	18.8	$	—		$	16.4		$	—		$	35.2
Payables to (receivables from) affiliates, net		2,390.8		(2,449.9	)		59.1			—			—
Liabilities from coal trading activities, net		—		29.2			50.7			—			79.9
Deferred income taxes		—		—			11.0			(11.0	)		—
Accounts payable and accrued expenses		93.5		622.4			385.4			—			1,101.3
Total current liabilities		2,503.1		(1,798.3	)		522.6			(11.0	)		1,216.4
Long-term debt, less current maturities		2,625.7		0.1			101.8			—			2,727.6
Deferred income taxes		—		247.2			250.2			(176.9	)		320.5
Notes payable to (receivables from) affiliates, net		819.1		(821.8	)		2.7			—			—
Other noncurrent liabilities		77.0		1,681.1			105.0			—			1,863.1
Total liabilities		6,024.9		(691.7	)		982.3			(187.9	)		6,127.6
Peabody Energy Corporation’s stockholders’ equity		3,955.3		5,829.9			3,122.3			(8,952.2	)		3,955.3
Noncontrolling interests		—		—			14.9			—			14.9
Total stockholders’ equity		3,955.3		5,829.9			3,137.2			(8,952.2	)		3,970.2
Total liabilities and stockholders’ equity	$	9,980.2	$	5,138.2		$	4,119.5		$	(9,140.1	)	$	10,097.8

30

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Unaudited Supplemental Condensed Consolidated Balance Sheets

	December 31, 2009
	Parent		Guarantor			Non-Guarantor			Reclassifications/
	Company		Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Assets
Current assets
Cash and cash equivalents	$	368.4	$	0.2		$	620.2		$	—		$	988.8
Accounts receivable, net		0.6		55.5			246.9			—			303.0
Inventories		—		152.5			172.6			—			325.1
Assets from coal trading activities, net		—		92.8			184.0			—			276.8
Deferred income taxes		11.6		56.5			—			(28.1	)		40.0
Other current assets		133.9		30.7			90.7			—			255.3
Total current assets		514.5		388.2			1,314.4			(28.1	)		2,189.0
Property, plant, equipment and mine development
Land and coal interests		—		4,807.3			2,750.0			—			7,557.3
Buildings and improvements		—		783.4			124.6			—			908.0
Machinery and equipment		—		1,117.3			273.9			—			1,391.2
Less: accumulated depreciation, depletion and amortization		—		(2,096.6	)		(498.4	)		—			(2,595.0	)
Property, plant, equipment and mine development, net		—		4,611.4			2,650.1			—			7,261.5
Deferred income taxes		124.0		—			—			(124.0	)		—
Investments and other assets		8,893.5		110.5			32.0			(8,531.2	)		504.8
Total assets	$	9,532.0	$	5,110.1		$	3,996.5		$	(8,683.3	)	$	9,955.3
Liabilities and Stockholders’ Equity
Current liabilities
Current maturities of long-term debt	$	—	$	—		$	14.1		$	—		$	14.1
Payables to (receivables from) affiliates, net		1,937.2		(1,975.9	)		38.7			—			—
Liabilities from coal trading activities, net		—		45.1			65.5			—			110.6
Deferred income taxes		—		—			28.1			(28.1	)		—
Accounts payable and accrued expenses		106.6		661.7			419.4			—			1,187.7
Total current liabilities		2,043.8		(1,269.1	)		565.8			(28.1	)		1,312.4
Long-term debt, less current maturities		2,635.4		0.1			102.7			—			2,738.2
Deferred income taxes		—		173.3			249.8			(124.0	)		299.1
Notes payable to (receivables from) affiliates, net		1,032.5		(1,035.0	)		2.5			—			—
Other noncurrent liabilities		70.6		1,667.8			111.3			—			1,849.7
Total liabilities		5,782.3		(462.9	)		1,032.1			(152.1	)		6,199.4
Peabody Energy Corporation’s stockholders’ equity		3,749.7		5,573.0			2,958.2			(8,531.2	)		3,749.7
Noncontrolling interests		—		—			6.2			—			6.2
Total stockholders’ equity		3,749.7		5,573.0			2,964.4			(8,531.2	)		3,755.9
Total liabilities and stockholders’ equity	$	9,532.0	$	5,110.1		$	3,996.5		$	(8,683.3	)	$	9,955.3

31

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Unaudited Supplemental Condensed Consolidated Statements of Cash Flows

	Six Months Ended June 30, 2010
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Consolidated
	(Dollars in millions)
Cash Flows From Operating Activities
Net cash provided by (used in) continuing operations	$	(106.1	)	$	454.1		$	118.3		$	466.3
Net cash used in discontinued operations		(8.8	)		(1.1	)		—			(9.9	)
Net cash provided by (used in) operating activities		(114.9	)		453.0			118.3			456.4
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development		—			(159.3	)		(28.2	)		(187.5	)
Investment in Prairie State Energy Campus		—			(30.5	)		—			(30.5	)
Proceeds from disposal of assets, net of notes receivable		—			4.9			1.2			6.1
Additions to advance mining royalties		—			(1.2	)		(0.1	)		(1.3	)
Investment in equity affiliates and joint ventures		—			(15.0	)		(2.4	)		(17.4	)
Other, net		—			(3.1	)		—			(3.1	)
Net cash used in investing activities		—			(204.2	)		(29.5	)		(233.7	)
Cash Flows From Financing Activities
Proceeds from long-term debt		500.0			—			—			500.0
Payments of long-term debt		(490.3	)		—			(5.4	)		(495.7	)
Dividends paid		(37.6	)		—			—			(37.6	)
Payment of debt issuance costs		(21.9	)		—			—			(21.9	)
Proceeds from stock options exercised		2.4			—			—			2.4
Other, net		2.8			(2.4	)		(2.1	)		(1.7	)
Transactions with affiliates, net		240.1			(246.4	)		6.3			—
Net cash provided by (used in) financing activities		195.5			(248.8	)		(1.2	)		(54.5	)
Net change in cash and cash equivalents		80.6			—			87.6			168.2
Cash and cash equivalents at beginning of period		368.4			0.2			620.2			988.8
Cash and cash equivalents at end of period	$	449.0		$	0.2		$	707.8		$	1,157.0

32

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Unaudited Supplemental Condensed Consolidated Statements of Cash Flows

	Six Months Ended June 30, 2009
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Consolidated
	(Dollars in millions)
Cash Flows From Operating Activities
Net cash provided by (used in) continuing operations	$	(34.6	)	$	142.6		$	118.4		$	226.4
Net cash provided by (used in) discontinued operations		8.5			(1.7	)		(1.7	)		5.1
Net cash provided by (used in) operating activities		(26.1	)		140.9			116.7			231.5
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development		—			(59.5	)		(22.4	)		(81.9	)
Investment in Prairie State Energy Campus		—			(24.5	)		—			(24.5	)
Federal coal lease expenditures		—			(123.6	)		—			(123.6	)
Proceeds from disposal of assets, net of notes receivable		—			34.0			1.4			35.4
Additions to advance mining royalties		—			(3.3	)		(0.1	)		(3.4	)
Investments in equity affiliates and joint ventures		—			—			(10.0	)		(10.0	)
Net cash used in continuing operations		—			(176.9	)		(31.1	)		(208.0	)
Net cash used in discontinued operations		—			—			(0.3	)		(0.3	)
Net cash used in investing activities		—			(176.9	)		(31.4	)		(208.3	)
Cash Flows From Financing Activities
Payments of long-term debt		—			—			(6.0	)		(6.0	)
Dividends paid		(32.1	)		—			—			(32.1	)
Proceeds from stock options exercised		0.6			—			—			0.6
Other, net		2.3			—			8.3			10.6
Transactions with affiliates, net		(29.3	)		35.9			(6.6	)		—
Net cash provided by (used in) financing activities		(58.5	)		35.9			(4.3	)		(26.9	)
Net change in cash and cash equivalents		(84.6	)		(0.1	)		81.0			(3.7	)
Cash and cash equivalents at beginning of period		161.2			4.5			284.0			449.7
Cash and cash equivalents at end of period	$	76.6		$	4.4		$	365.0		$	446.0

33

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Cautionary Notice Regarding Forward-Looking Statements

     This report includes statements of our expectations, intentions, plans and beliefs that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 and are intended to come within the safe harbor protection provided by those sections. These statements relate to future events or our future financial performance, including, without limitation, the section captioned “Outlook” in Management’s Discussion and Analysis of Financial Condition and Results of Operations. We use words such as “anticipate,” “believe,” “expect,” “may,” “project,” “should,” “estimate,” or “plan” or other similar words to identify forward-looking statements.

     Without limiting the foregoing, all statements relating to our future operating results, anticipated capital expenditures, future cash flows and borrowings, and sources of funding are forward-looking statements and speak only as of the date of this report. These forward-looking statements are based on numerous assumptions that we believe are reasonable, but are subject to a wide range of uncertainties and business risks and actual results may differ materially from those discussed in these statements. Among the factors that could cause actual results to differ materially are:

• demand for coal in United States (U.S.), China and other international power generation and steel production markets;

• price volatility and demand, particularly in higher-margin products and in our trading and brokerage businesses;

• reductions and/or deferrals of purchases by major customers and ability to renew sales contracts;

• credit and performance risks associated with customers, suppliers, trading, banks and other financial counterparties;

• geologic, equipment, permitting and operational risks related to mining;

• transportation availability, performance and costs;

• availability, timing of delivery and costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires;

• impact of weather on demand, production and transportation;

• successful implementation of business strategies, including our Btu Conversion and generation development initiatives;

• negotiation of labor contracts, employee relations and workforce availability;

• changes in postretirement benefit and pension obligations and funding requirements;

• replacement and development of coal reserves;

• access to capital and credit markets and availability and costs of credit, margin capacity, surety bonds, letters of credit, and insurance;

• effects of changes in interest rates and currency exchange rates (primarily the Australian dollar);

• effects of acquisitions or divestitures;

• economic strength and political stability of countries in which we have operations or serve customers;

• legislation, regulations and court decisions or other government actions, including new environmental requirements, changes in income tax regulations or other regulatory taxes;

• litigation, including claims not yet asserted;

• terrorist attacks or threats;

• impacts of pandemic illnesses; and

• other factors, including those discussed in Legal Proceedings.

     When considering these forward-looking statements, you should keep in mind the cautionary statements in this document and in our other Securities and Exchange Commission (SEC) filings, including the more detailed discussion of these factors, as well as other factors that could affect our results, contained in Item 1A. “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2009. These forward-looking statements speak only as of the date on which such statements were made, and we undertake no obligation to update these statements except as required by federal securities laws.

34

Overview

     We are the world’s largest private sector coal company, with majority interests in 28 coal mining operations in the U.S. and Australia. In 2009, we produced 210.0 million tons of coal and sold 243.6 million tons of coal.

     We typically sell coal to utility customers under long-term contracts (those with terms longer than one year). During 2009, approximately 93% of our worldwide sales (by volume) were under long-term contracts. For the year ended December 31, 2009, 81% of our total sales (by volume) were to U.S. electricity generators, 17% were to customers outside the U.S. and 2% were to the U.S. industrial sector. We conduct business through four principal operating segments: Western U.S. Mining, Midwestern U.S. Mining, Australian Mining, and Trading and Brokerage. Our fifth segment, Corporate and Other, includes mining and export/transportation joint ventures, energy-related commercial activities, as well as the management of our vast coal reserve and real estate holdings.

     We continue to explore Btu Conversion projects designed to expand the uses of coal through coal-to-liquids and coal gasification technologies. We are also participating in the advancement of clean coal technologies, including carbon capture and storage, in the U.S., China and Australia.

 Recent Events

     On May 9, 2010, we announced that we had submitted a definitive proposal to acquire a controlling interest in Macarthur Coal Limited (Macarthur). Under the proposal, Macarthur shareholders would have received a cash price of $15.00 Australian dollars per share, valuing Macarthur at $3.8 billion Australian dollars ($3.4 billion U.S. dollars). On May 18, 2010, Macarthur’s Board of Directors elected not to recommend our proposal to its shareholders and our proposal has expired.

     We control a 17.7% interest in the Newcastle Coal Infrastructure Group (NCIG), which is developing a coal transloading facility in Newcastle, Australia. In the second quarter of 2010, stage one of construction was completed and the facility began shipping coal. At full capacity, the facility is expected to provide us with 5 to 6 million tons of additional throughput capacity per year, which is expected in the first quarter of 2011.

     Our Bear Run Mine in Sullivan County, Indiana shipped its first coal in May 2010. The mine is projected to be the largest surface coal mine in the eastern U.S. which, at full production levels, will have an installed capacity of approximately 8 million tons of coal annually with the ability to ramp up to 10 to 12 million tons if demand exists. The mine will initially supply two major Midwestern electricity generators under long-term contracts with terms of up to 17 years. Sales are expected to be 3.0 to 3.5 million tons in 2010 and are expected to ramp up to 8 million tons in 2012.

     In June 2010, we entered into a 50-50 joint venture agreement in Mongolia with Winsway Coking Coal Holdings Ltd. (Winsway), creating Peabody-Winsway Resources, after Winsway purchased the 50% interest in the joint venture formerly owned by Polo Resources. Winsway distributes and transports coal from Mongolia and other countries into China through its integrated service platform. Peabody-Winsway Resources holds coal and uranium licenses in Mongolia, and is conducting an active coal exploration program primarily in the South Gobi region and throughout Mongolia.

Results of Operations

     The results of operations for all periods presented reflect the assets, liabilities and results of operations from subsidiaries spun off as Patriot Coal Corporation (Patriot) as discontinued operations. We also have classified as discontinued operations those operations recently divested, as well as certain non-strategic mining assets held for sale where we have committed to the divestiture of such assets.

35

Adjusted EBITDA

     The discussion of our results of operations below includes references to and analysis of our segments’ Adjusted EBITDA results. We define Adjusted EBITDA as income from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expense and depreciation, depletion and amortization. Adjusted EBITDA is used by management to measure our segments’ operating performance, and management also believes it is a useful indicator of our ability to meet debt service and capital expenditure requirements. Because Adjusted EBITDA is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies. Adjusted EBITDA is reconciled to its most comparable measure, under U.S. generally accepted accounting principles (GAAP), in Note 11 to our unaudited condensed consolidated financial statements.

Three and Six Months Ended June 30, 2010 Compared to Three and Six Months Ended June 30, 2009

 Summary

     We believe markets are continuing to recover from the global economic recession, with the international markets led by rising coal imports in China, India, and the recovering developed economies in Asia. In the U.S., coal market fundamentals have improved due to a combination of the improving economy, new coal-fueled facilities, weather-related demand and some reversal of gas-fueled electricity back to coal. Our analyses of general business conditions indicate the following:

• Third quarter 2010 benchmark metallurgical coal pricing in Australia is exceeding second quarter 2010 pricing;

• U.S. coal production remains 3% lower than 2009 levels;

• U.S. coal consumption for electricity generation has increased 6% year-to-date; and

• Customer inventories of coal in the U.S. are currently 8% below 2009 levels and 17% lower than this time last year for Powder River Basin coal, our largest U.S. production base.

     We continue to focus on cost control and productivity improvements, increasing contributions from our high-margin operations and exercising capital discipline. We ended the quarter with total available liquidity of $2.4 billion, consisting of cash on hand, our revolving credit facility and our accounts receivable securitization program.

     Revenue increased for both periods compared to the prior year (three months, $323.2 million; six months, $385.8 million) and Segment Adjusted EBITDA increased over the prior year (three months, $128.0 million; six months, $166.7 million) led by higher Australian metallurgical coal volumes and pricing secured in the second quarter of the current year, and a change in mix toward our higher-margin products within our Western U.S. Mining operations.

     Income from continuing operations, net of income taxes, increased for both periods compared to the prior year (three months, $124.7 million; six months, $120.6 million) due to the increase in Segment Adjusted EBITDA discussed above and decreased income taxes (three months), partially offset by decreased Corporate and Other Adjusted EBITDA and increased depreciation, depletion and amortization and interest expense.

 Tons Sold

     The following table presents tons sold by operating segment:

	Three Months Ended										Six Months Ended
	June 30,				Increase (Decrease)						June 30,				Increase (Decrease)
	2010		2009		Tons			%			2010		2009		Tons			%
								(Tons in millions)
Western U.S. Mining		39.8		38.7		1.1			2.8	%		79.8		79.5		0.3			0.4	%
Midwestern U.S. Mining		7.3		8.3		(1.0	)		(12.0	)%		14.4		16.1		(1.7	)		(10.6	)%
Australian Mining		6.4		5.0		1.4			28.0	%		12.6		9.4		3.2			34.0	%
Trading and Brokerage		6.2		7.4		(1.2	)		(16.2	)%		11.2		13.9		(2.7	)		(19.4	)%
Total tons sold		59.7		59.4		0.3			0.5	%		118.0		118.9		(0.9	)		(0.8	)%

36

 Revenues

     The following table presents revenues by operating segment:

	Three Months Ended				Increase (Decrease)						Six Months Ended				Increase (Decrease)
	June 30,				to Revenues						June 30,				to Revenues
	2010		2009		$			%			2010		2009		$			%
	(Dollars in millions)
Western U.S. Mining	$	652.1	$	635.4	$	16.7			2.6	%	$	1,314.2	$	1,289.2	$	25.0			1.9	%
Midwestern U.S. Mining		323.3		339.8		(16.5	)		(4.9	)%		632.7		650.5		(17.8	)		(2.7	)%
Australian Mining		597.4		309.0		288.4			93.3	%		1,043.9		669.3		374.6			56.0	%
Trading and Brokerage		81.8		48.4		33.4			69.0	%		171.9		171.9		—			0.0	%
Corporate and Other		6.8		5.6		1.2			21.4	%		14.3		10.3		4.0			38.8	%
Total revenues	$	1,661.4	$	1,338.2	$	323.2			24.2	%	$	3,177.0	$	2,791.2	$	385.8			13.8	%

     Total revenues increased for the three and six months ended June 30, 2010 compared to the prior year due to the following:

• Australian Mining operations’ revenues were higher for both periods compared to the prior year as discussed below:

o The revenue increase for the three months ended was driven by an increase in our weighted average sales price (49.4%) reflecting higher pricing secured in the second quarter for both thermal and metallurgical coal. Volumes also increased over the prior year (28.0%) as the demand for our metallurgical coal continued to increase from the first quarter (second quarter metallurgical coal shipments of 2.2 million tons were 1.2 million tons, or 120%, greater than the prior year).

o The revenue increase for the six months ended was driven by an increase in volumes (34.0%) due to increased demand for metallurgical coal (metallurgical coal shipments of 4.5 million tons were 2.6 million tons, or 137%, greater than the prior year). The metallurgical coal demand increase reflects the current year market recovery as discussed above, coupled with prior year customer destocking of inventory and lower capacity utilization at steel customers. Our weighted average sales price increased (15.6%), reflecting a higher mix of metallurgical coal shipments.

• Western U.S. Mining operations’ revenues were modestly higher for both periods compared to the prior year. For the six months ended, the increase was due to a higher weighted average sales price while volumes were relatively flat compared to the prior year. By contrast for the three months ended, volumes increased while the weighted average sales price was consistent with the prior year.

• Midwestern U.S. Mining operations’ revenues were lower for both periods compared to the prior year due to decreased shipments resulting from reduced demand. Partially offsetting the impact of the decreased shipments was an increase in weighted average sales price (three months, 8.3%; six months, 8.7%) driven by contractual price increases.

• Trading and Brokerage revenues increased for the three months ended compared to the prior year due primarily to a higher mix of physical activity reflected on a gross basis as compared to the prior year.

37

Segment Adjusted EBITDA

     The following table presents segment Adjusted EBITDA by operating segment:

					Increase (Decrease) to										Increase (Decrease) to
	Three Months Ended				Segment Adjusted						Six Months Ended				Segment Adjusted
	June 30,				EBITDA						June 30,				EBITDA
	2010		2009		$			%			2010		2009		$			%
	(Dollars in millions)
Western U.S. Mining	$	207.3	$	152.1	$	55.2			36.3	%	$	415.2	$	335.3	$	79.9			23.8	%
Midwestern U.S. Mining		71.4		73.3		(1.9	)		(2.6	)%		145.5		140.4		5.1			3.6	%
Australian Mining		223.6		127.7		95.9			75.1	%		346.9		210.9		136.0			64.5	%
Trading and Brokerage		14.3		35.5		(21.2	)		(59.7	)%		46.7		101.0		(54.3	)		(53.8	)%
Total Segment Adjusted EBITDA	$	516.6	$	388.6	$	128.0			32.9	%	$	954.3	$	787.6	$	166.7			21.2	%

     Australian Mining operations’ Adjusted EBITDA increased for both periods compared to the prior year as discussed below:

• Australian Mining operations’ Adjusted EBITDA increase for the three months ended was driven by an increase in our weighted average sales price and increased volumes as discussed above. Partially offsetting the above improvements were higher costs, reflecting a higher mix of metallurgical coal shipments, an unfavorable foreign currency impact on operating costs, net of hedging, and increased royalty expense associated with our higher-priced metallurgical coal shipments.

• Australian Mining operations’ Adjusted EBITDA increase for the six months ended was driven by an increase in volumes and product mix change as discussed above, productivity improvements at our North Goonyella and Wambo Underground Mines, fewer longwall moves and lower stripping ratios at some of our mines. Partially offsetting the above improvements were higher costs associated with the greater mix of metallurgical coal shipments, an unfavorable foreign currency impact on operating costs, net of hedging and increased demurrage costs.

     Western U.S. Mining operations’ Adjusted EBITDA increased for both periods compared to the prior year due to lower repairs and maintenance costs due to timing of repairs and improved equipment efficiency at our North Antelope Rochelle Mine, reflecting the full benefit of our truck and shovel fleet upgrades and the elimination of a continuous miner unit at our Twentymile Mine as the prior year includes costs incurred during the preparation of a new mining area (three months, $33.6 million; six months, $50.1 million), lower materials and supplies costs (three months, $9.4 million; six months, $12.0 million) and a shift in volume to our higher-margin operations.

     Midwestern U.S. Mining operations’ Adjusted EBITDA decreased for the three months ended June 30, 2010 compared to the prior year due to lower volume as discussed above and higher costs per ton related to the start-up of our Bear Run Mine and mining in more difficult geological conditions, partially offset by an increase in the weighted average sales price as discussed above. The results for the six months ended June 30, 2010 increased over the prior year due to an increase in the weighted average sales price as discussed above, partially offset by lower volume driven by decreased demand and higher costs per ton related to the start-up of our Bear Run Mine.

     Trading and Brokerage operations’ Adjusted EBITDA decreased for both periods compared to the prior year primarily due to lower exports due to the weak Atlantic market along with vessel timing and overall lower trading levels.

38

  Income From Continuing Operations Before Income Taxes

     The following table presents income from continuing operations before income taxes:

	Three Months Ended						Increase (Decrease)						Six Months Ended						Increase (Decrease)
	June 30,						to Income						June 30,						to Income
	2010			2009			$			%			2010			2009			$			%
	(Dollars in millions)
Total Segment Adjusted EBITDA	$	516.6		$	388.6		$	128.0			32.9	%	$	954.3		$	787.6		$	166.7			21.2	%
Corporate and Other Adjusted EBITDA (1)		(76.2	)		(62.4	)		(13.8	)		(22.1	)%		(156.7	)		(136.0	)		(20.7	)		(15.2	)%
Depreciation, depletion and amortization		(105.1	)		(101.2	)		(3.9	)		(3.9	)%		(210.6	)		(197.5	)		(13.1	)		(6.6	)%
Asset retirement obligation expense		(10.9	)		(9.6	)		(1.3	)		(13.5	)%		(20.4	)		(19.0	)		(1.4	)		(7.4	)%
Interest expense		(57.9	)		(48.2	)		(9.7	)		(20.1	)%		(107.9	)		(99.3	)		(8.6	)		(8.7	)%
Interest income		1.6			1.2			0.4			33.3	%		2.6			4.0			(1.4	)		(35.0	)%
Income from continuing operations before income taxes	$	268.1		$	168.4		$	99.7			59.2	%	$	461.3		$	339.8		$	121.5			35.8	%

⁽¹⁾ Corporate and Other Adjusted EBITDA results include selling and administrative expenses, equity income (loss) from our joint ventures, net gains on asset disposals or exchanges, costs associated with past mining obligations and revenues and expenses related to our other commercial activities such as generation development and Btu Conversion development costs.

     Income from continuing operations before income taxes was higher for both periods compared to the prior year primarily due to the higher Total Segment Adjusted EBITDA discussed above, partially offset by lower Corporate and Other Adjusted EBITDA and higher depreciation, depletion and amortization expense and interest expense.

• The decrease in Corporate and Other Adjusted EBITDA for the three and six months ended June 30, 2010 compared to the prior year was primarily due to a current year increase in selling and administrative expenses related to an increase in headcount and professional services costs to support our international expansion, acquisition activity and other growth initiatives. These decreases to Corporate and Other Adjusted EBITDA were partially offset by improved results from equity affiliates due to prior year operating losses from our joint venture interest in Carbones del Guasare (three months, $4.9 million; six months, $7.4 million) and current earnings (three and six months, $10.0 million) associated with transaction services related to our Mongolian joint venture.

• Depreciation, depletion and amortization was higher for the three and six months ended June 30, 2010 compared to the prior year due to increased production at our Australian mines reflecting higher demand and the impact of mining higher value coal reserves at our North Antelope Rochelle Mine.

• Interest expense was higher for the three and six months ended June 30, 2010 compared to the prior year primarily due to refinancing charges ($9.3 million) associated with our new five-year Credit Facility, which were largely due to cancellation of an interest rate swap.

39

 Net Income Attributable to Common Stockholders

     The following table presents net income attributable to common stockholders:

	Three Months Ended						Increase (Decrease)						Six Months Ended						Increase (Decrease)
	June 30,						to Income						June 30,						to Income
	2010			2009			$			%			2010			2009			$			%
	(Dollars in millions)
Income from continuing operations before income taxes	$	268.1		$	168.4		$	99.7			59.2	%	$	461.3		$	339.8		$	121.5			35.8	%
Income tax provision		(53.4	)		(78.4	)		25.0			31.9	%		(109.5	)		(108.6	)		(0.9	)		(0.8	)%
Income from continuing operations, net of income taxes		214.7			90.0			124.7			138.6	%		351.8			231.2			120.6			52.2	%
Income (loss) from discontinued operations		(0.5	)		(8.0	)		7.5			93.8	%		(0.9	)		26.0			(26.9	)		(103.5	)%
Net income		214.2			82.0			132.2			161.2	%		350.9			257.2			93.7			36.4	%
Less: Net income attributable to noncontrolling interests		8.0			2.8			(5.2	)		(185.7	)%		11.0			8.0			(3.0	)		(37.5	)%
Net income attributable to common stockholders	$	206.2		$	79.2		$	127.0			160.4	%	$	339.9		$	249.2		$	90.7			36.4	%

     Net income attributable to common stockholders increased for both periods compared to the prior year due to the increased income from continuing operations before income taxes as discussed above.

Income tax provision was impacted by the following:

• Current year benefit as compared to a prior year expense associated with the remeasurement of non-U.S. tax accounts as a result of the weakening Australian dollar against the U.S. dollar compared to the prior year (three months, $67.0 million; six months, $60.7 million; the table below illustrates the foreign currency exchange rate fluctuations); and

• Lower expense in the current year due to the reduction of our gross unrecognized tax benefit of $15.2 million resulting from the completion of the Internal Revenue Service examination of the 2005 federal income tax year; partially offset by

• Increased expense due to higher current year earnings (three months, $34.9 million; six months, $42.5 million), lower current year percentage depletion benefit (three months, $9.2 million; six months, $16.2 million) and increased reserves against tax credits (three months, $8.0 million; six months, $11.6 million).

	June 30,				March 31,				December 31,
	2010		2009		2010		2009		2009		2008
Australian dollar to U.S. dollar exchange rate	$	0.8523	$	0.8114	$	0.9159	$	0.6873	$	0.8969	$	0.6928

     Income (loss) from discontinued operations for the six months ended June 30, 2010 was $26.9 million lower than the prior year due to a coal excise tax refund receivable of approximately $35 million recorded during the three months ended March 31, 2009. See Note 2 to our consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2009 for more information related to the excise tax refund receivable.

40

Outlook

     Near-Term Outlook

     Global economies continue to show signs of improvement, with the June economic projections of the Federal Reserve forecasting a 3.0% to 3.5% economic expansion for 2010. The Asia-Pacific markets are expected to continue to outpace the U.S. and European markets in economic growth and therefore in steel production and electricity generation. China’s gross domestic product (GDP) grew at an annual rate of 10.3% during the second quarter of 2010. India’s GDP grew at an annual pace of 8.6% during the first quarter of 2010. According to the World Steel Association, annualized June year-to-date steel production indicates global steel production is on pace to exceed 2009 levels by 16%, and 2008 levels by 6%. Industry reports forecast that, globally, more than 85 gigawatts of new coal-fueled generation are under construction and expected to come on line during 2010, more than 75% of which are in China and India. New global coal-fueled generation for 2010 is estimated to require approximately 375 million tons of coal annually. Leading industry analysts estimate global seaborne coal demand will increase 15% in 2010, driven by the strong growth in the Pacific markets that more than offsets continued sluggishness in the Atlantic market from high stockpiles and low natural gas prices.

     U.S. markets also continue to recover from the recession, with the Energy Information Administration (EIA) forecasting coal-based electricity generation to be up 4.6% for 2010. Genscape, Inc. estimates that U.S. coal stockpiles at electric utilities are declining, with a nearly 15 million ton draw over the five-week period ended July 17, 2010, more than double the comparable five-year historical decline. According to third-party industry reports, an estimated 40 million tons of annual coal consumption by U.S. generators was lost to natural gas generation in 2009 due to low natural gas prices. In 2010, approximately half of that volume is expected to return to coal consumption. The EIA estimates 2010 coal consumption will be more than 40 million tons above 2009’s level, led by increased electric power sector needs. Higher demand combined with the EIA’s estimates for slightly lower 2010 coal production is expected to lead to a decrease in customer inventories in 2010. Improving industry fundamentals have led to higher coal prices. Over the past year, index coal prices have rebounded in all regions, including more than 40% for Powder River Basin coal and nearly 30% for Illinois Basin products.

     As of July 20, 2010, our full-year 2010 sales targets are approximately 185 to 195 million tons in the U.S. and 27 to 29 million tons in Australia. Total 2010 sales are expected to be in a range of 240 to 260 million tons. We may continue to adjust our production levels in response to changes in market demand.

     We are fully contracted for 2010 at planned production levels in the U.S. As of July 20, 2010, we had approximately 2.5 million tons of unpriced Australian metallurgical coal and an estimated 1.0 million tons of unpriced Australian export thermal coal, both for fourth quarter 2010 deliveries.

     Because of the tightness in Pacific supply-demand fundamentals, reference high-quality hard coking coal settled for quarterly contracts commencing July 1 at $225 per tonne, a 12.5% increase over the April 1 $200 per tonne reference price. As of June 30, 2010, annual index pricing for Newcastle quality thermal coal was $100 per tonne with the futures pricing above $107 per tonne in 2013, slightly ahead of pricing one quarter ago.

     We continue to manage costs and operating performance in an effort to mitigate external cost pressures, geologic conditions and potential shipping delays resulting from adverse port and rail performance. To mitigate the external cost pressures, we have an ongoing company-wide initiative to instill best practices at all operations. We may have higher per ton costs as a result of below-optimal production levels due to market-driven changes in demand. We may also encounter poor geologic conditions, lower third-party contract miner or brokerage performance or unforeseen equipment problems that limit our ability to produce at forecasted levels. To the extent upward pressure on costs exceeds our ability to realize sales increases, or if we experience unanticipated operating or transportation difficulties, our operating margins would be negatively impacted. Reductions in the relative cost of other fuels, including natural gas, could impact the use of coal for electricity generation. See Cautionary Notice Regarding Forward-Looking Statements and Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2009 for additional considerations regarding our outlook.

41

     We rely on ongoing access to worldwide financial markets for capital, insurance, hedging and investments through a wide variety of financial instruments and contracts. To the extent these markets are not available or increase significantly in cost, this could have a negative impact on our ability to meet our business goals. Similarly, many of our customers and suppliers rely on the availability of the financial markets to secure the necessary financing and financial surety (letters of credit, performance bonds, etc.) to complete transactions with us. To the extent customers and suppliers are not able to secure this financial support, it could have a negative impact on our results of operations and/or counterparty credit exposure.

     On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act). The Dodd-Frank Act includes a number of provisions applicable to us in the areas of corporate governance, executive compensation and mine safety and extractive industries disclosure. In addition, the Dodd-Frank Act imposes additional regulation of swap transactions involving our hedging and our Trading and Brokerage activities. Although the Dodd-Frank Act became generally effective upon its enactment, many provisions have extended implementation periods and delayed effective dates and require further action by the federal regulatory authorities. As a result, in many respects the ultimate impact of the Dodd-Frank Act on us will not be fully known for an extended period of time. We do expect that the Dodd-Frank Act will result in a change in some of our business practices as well as increased compliance and transaction costs associated with our hedging and Trading and Brokerage activities.

     Long-Term Outlook

     Our long-term global outlook remains positive. According to the BP Statistical Review of World Energy, coal has been the fastest-growing fuel in the world for the past decade.

     The International Energy Agency’s (IEA) World Energy Outlook estimates world primary energy demand will grow 40% between 2007 and 2030, with demand for coal rising 53%. China and India alone account for more than half of the expected incremental energy demand.

     Coal is expected to retain its strong presence as a fuel for the power sector worldwide, with its share of the power generation mix projected by the IEA to rise from 41% in 2007 to 44% in 2030. Currently, we estimate more than 300 gigawatts of coal-fueled electricity generating plants are under construction around the world, representing more than a billion tons of annual coal demand expected to come online in the next several years. While some planned U.S. coal-based plants have been cancelled in recent years, 13 gigawatts of new coal-based generating capacity have been completed in 2010 or are under construction, representing approximately 50 million tons of annual coal demand once they become operational.

     We believe that Btu Conversion applications such as coal-to-gas (CTG) and coal-to-liquids (CTL) plants represent an avenue for potential long-term industry growth. The EIA continues to project an increase in demand for unconventional sources of transportation fuel such as CTL. In addition, China and India are developing CTG and CTL facilities.

     The IEA projects natural gas demand will grow 1.5% per year to just under 4,310 billion cubic meters in 2030. The biggest increase in absolute terms is expected in the Middle East, which holds the majority of the world’s proven reserves, and non-OECD Asia. North America and Eastern Europe/Eurasia are expected to remain the leading gas consumers in 2030, even though their demand is expected to rise less in percentage terms than almost anywhere else globally. Globally, the share of hydro and renewables is projected to rise four percentage points to 22% between 2007 and 2030. Nuclear power is expected to grow in all major regions with the exception of Europe, but its share in total generation is expected to fall between 2007 and 2030.

     On May 2, 2010, the Australian government released a report on Australia’s Future Tax System, which included a recommendation to replace the current resource taxing arrangements imposed on nonrenewable resources by the Australian and state governments with a uniform resource rent tax (the Resource Tax) imposed and administered by the Australian government. As proposed, the Resource Tax would be profit-based and would apply to non-renewable resources projects, including existing projects. On July 2, 2010, the Australian government announced changes to the Resource Tax and proposed a new minerals resource rent tax (the MRRT). The MRRT would still be profit-based, but measures were introduced to lessen the impact of the MRRT. The MRRT is not yet law in Australia and may not become law. The draft law is expected to be presented to the Australian Parliament in late 2011, and if the MRRT becomes law, it is intended to become effective July 1, 2012. If the MRRT were to become law, it may affect the financial performance of our Australian operations.

42

     We continue to support clean coal technology development and other initiatives addressing carbon dioxide concerns through our participation in a number of projects in the U.S., China and Australia. In addition, clean coal technology development in the U.S. is being accelerated by funding under the American Recovery and Reinvestment Act of 2009 and by the formation of an Interagency Task Force on Carbon Capture and Storage to develop a comprehensive and coordinated federal strategy to speed the commercial development of clean coal technologies.

     Enactment of laws or passage of regulations regarding emissions from the combustion of coal by the U.S. or some of its states or by other countries, or other actions to limit such emissions, could result in electricity generators switching from coal to other fuel sources. The potential financial impact on us of future laws or regulations will depend upon the degree to which any such laws or regulations force electricity generators to diminish their reliance on coal as a fuel source. That, in turn, will depend on a number of factors, including the specific requirements imposed by any such laws or regulations, the time periods over which those laws or regulations would be phased in and the state of commercial development and deployment of carbon capture and storage technologies. In view of the significant uncertainty surrounding each of these factors, it is not possible for us to reasonably predict the impact that any such laws or regulations may have on our results of operations, financial condition or cash flows.

Liquidity and Capital Resources

     Our primary sources of cash include sales of our coal production to customers, cash generated from our trading and brokerage activities, sales of non-core assets and financing transactions. Our primary uses of cash include our cash costs of coal production, capital expenditures, federal coal lease payments, debt service costs (interest and principal), costs related to past mining obligations and investments in growth projects. Our ability to pay dividends, service our debt and acquire new productive assets or businesses is dependent upon our ability to continue to generate cash from the primary sources noted above in excess of the primary uses. Future dividends and share repurchases, among other restricted items, are subject to limitations imposed in the covenants of certain of our debt instruments. We generally fund our capital expenditure requirements with cash generated from operations.

     We believe our available borrowing capacity and operating cash flows will be sufficient in the near term. As of June 30, 2010, we had available liquidity of $2.4 billion, consisting of cash on hand, our revolving credit facility and our accounts receivable securitization program.

     On June 18, 2010 we entered into an unsecured credit agreement (Credit Agreement) which established a $2.0 billion Credit Facility and replaced our third amended and restated credit agreement dated as of September 15, 2006. The Credit Agreement provides for a $1.5 billion revolving credit facility (the Revolver) and a $500.0 million term loan facility (the Term Loan). We have the option to request an increase in the capacity of the Credit Facility, provided the aggregate increase for the Revolver and Term Loan does not exceed $250.0 million and the minimum amount of the increase is $25.0 million, assuming conditions are met under the Credit Agreement. The Revolver also includes a swingline sub-facility where up to $50.0 million is available for same-day borrowings. The Revolver commitments and the Term Loan under the Credit Facility will mature on June 18, 2015.

     The Revolver replaced our previous $1.8 billion revolving credit facility and the Term Loan replaced our previous term loan facility (the previous term loan had a balance of $490.3 million at the time of replacement and at December 31, 2009). We capitalized $21.9 million in financing costs which will be amortized to interest expense over the five year term of the Credit Facility. We also had refinancing charges of $9.3 million, which primarily consisted of the cancellation of an interest rate swap associated with our previous credit facility.

     See Note 7 to our unaudited condensed consolidated financial statements for additional information on the new Credit Facility.

43

     The Pension Protection Act of 2006 (the Pension Protection Act), which was effective January 1, 2008, increased the long-term funding targets for single employer pension plans from 90% to 100%. “At risk” plans, as defined by the Pension Protection Act, are restricted from making full lump sum payments and from increasing benefits unless they are funded immediately, and are required to give participants notice regarding the at-risk status of the plan. If a plan falls below 60%, lump sum payments are prohibited and participant benefit accruals cease. During the six months ended June 30, 2010, we made discretionary contributions of approximately $19 million. We expect to make additional discretionary contributions of approximately $6 million during 2010. Total minimum and discretionary contributions in 2010 are expected to be approximately $28 million. These additional contributions will be made to avoid benefit payment restrictions.

     We also have a share repurchase program that has an available capacity of $700.4 million at June 30, 2010. While no repurchases have been made in 2010 under the program, repurchases may be made from time to time based on an evaluation of our outlook and general business conditions, as well as alternative investment and debt repayment options. The repurchase program does not have an expiration date and may be discontinued at any time.

     The NCIG coal transloading facility is backed by take or pay agreements. Financing for the next stage of construction is expected to close in August 2010. To cover a financing shortfall for stage two, we have committed to fund a pro-rata share of the financing along with the other NCIG shareholders. Our share is estimated to be $61 million Australian dollars (approximately $52 million U.S. dollars).

     A subsidiary of ours owns a 5.06% undivided interest in the Prairie State Energy Campus (Prairie State), a 1,600 megawatt coal-fuel electricity generation project currently under construction. We spent $30.5 million during the six months ended June 30, 2010 representing our 5.06% share of the construction costs. Included in “Investments and other assets” in the condensed consolidated balance sheets as of June 30, 2010 and December 31, 2009, are costs of $157.1 million and $126.6 million, respectively. Our share of total construction costs for Prairie State is expected to be approximately $210 million.

     We are an equity partner in GreenGen, a partnership to fund the construction in China of a near-zero emissions coal-fueled power plant with carbon capture and storage. During the six months ended June 30, 2010, we spent $3.1 million representing our 6.0% share of the construction costs, which is reflected as capitalized development costs as part of “Investments and other assets” in the condensed consolidated balance sheet. There were no expenditures for GreenGen for 2009. Our share of total construction costs for GreenGen is expected to be approximately $60 million U.S. dollars.

     Net cash provided by operating activities from continuing operations increased $239.9 million compared to the prior year primarily due to the following:

• an increase in operating cash flows generated from our Australian Mining operations;

• lower year-over-year inventory balances largely due to the higher inventory stockpiles in 2009 we experienced as a result of lower customer demand and delayed customer price settlements for high-value metallurgical coal shipments; and

• decreased cash usage for accounts payable and accrued expenses driven in part by the higher foreign income tax payments in 2009 that were associated with 2008 earnings.

     Net cash used in investing activities from continuing operations increased $25.7 million compared to the prior year due to higher current year capital spending of $105.6 million related primarily to our Bear Run Mine, $15.0 million of Btu Conversion investments in the current year, and the collection of a note receivable of $30.0 million in the prior year. Partially offsetting the above increases in cash used in investing activities were federal coal lease expenditures of $123.6 million in the prior year.

     Net cash used in financing activities increased $27.6 million compared to the prior year primarily due to the payment of debt issuance costs of $21.9 million in the current year related to the refinancing of our Credit Facility and a $5.5 million increase in dividends due to a change in the rate from $0.06 per share to $0.07 per share. The $500.0 million of proceeds from long-term debt represents the new Term Loan, which was used to pay off the $490.3 million balance due on our previous term loan facility.

44

     Our total indebtedness as of June 30, 2010 and December 31, 2009, consisted of the following:

	June 30,		December 31,
	2010		2009
	(Dollars in millions)
Term Loan	$	500.0	$	490.3
Convertible Junior Subordinated Debentures due 2066		372.4		371.5
7.375% Senior Notes due November 2016		650.0		650.0
6.875% Senior Notes due March 2013		650.0		650.0
7.875% Senior Notes due November 2026		247.2		247.1
5.875% Senior Notes due March 2016		218.1		218.1
6.84% Series C Bonds due December 2016		33.0		33.0
6.34% Series B Bonds due December 2014		15.0		15.0
Capital lease obligations		69.1		67.5
Fair value hedge adjustment		6.8		8.4
Other		1.2		1.4
Total	$	2,762.8	$	2,752.3

     Capital Expenditures. Capital expenditures for 2010 are anticipated to be between $600 million to $650 million. The planned expenditures include the completion of our Bear Run Mine in western Indiana, sustaining capital at our existing mines, expansion of our metallurgical and thermal coal export platform in Australia to serve the growth markets in Asia and funding of our Prairie State investment.

Contractual Obligations

     As discussed above in “Liquidity and Capital Resources” and in Note 7 to our unaudited condensed consolidated financial statements, we entered into a new Credit Facility during the second quarter of 2010, which had the following material changes to our contractual obligations:

• We repaid the then outstanding balance due of $490.3 million on our previous term loan facility, which was due in September 2011;

• Our new Term Loan, with an initial principal balance of $500.0 million, will be repaid quarterly at a rate of 1.25% per quarter commencing on December 31, 2010, with the final payment of all amounts outstanding due in June 2015; and

• Based on the June 30, 2010 interest rate of LIBOR plus 2.5%, or 2.85%, total interest payments over the five-year period will be approximately $65 million for the Credit Facility.

     There were no other significant changes to our contractual obligations since December 31, 2009.

Off-Balance Sheet Arrangements

     In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees, indemnifications, financial instruments with off-balance sheet risk, such as bank letters of credit and performance or surety bonds and our accounts receivable securitization. Assets and liabilities related to these arrangements are not reflected in our condensed consolidated balance sheets, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.

     Accounts Receivable Securitization. We have an accounts receivable securitization program (securitization program) through our wholly-owned, bankruptcy-remote subsidiary (Seller). Under the securitization program, beginning in 2010, we contribute, on a revolving basis, trade receivables of most of our U.S. subsidiaries to the Seller, which then sells the receivables in their entirety to a consortium of unaffiliated asset-backed commercial paper conduits (the Conduits). After the sale, we, as servicer of the assets, collect the receivables on behalf of the Conduits for a nominal servicing fee. We utilize

45

proceeds from the sale of our accounts receivable as an alternative to short-term borrowings under our Credit Facility, effectively managing our overall borrowing costs and providing an additional source for working capital. The securitization program was renewed in May 2009 and amended in December 2009 in order to qualify for sale accounting under a newly adopted accounting standard related to financial asset transfers. Prior to amending the securitization program, we sold senior undivided interests in certain of our accounts receivable and retained subordinated interests in those receivables. The current securitization program extends to May 2012, while the letter of credit commitment that supports the commercial paper facility underlying the securitization program must be renewed annually.

     The Seller is a separate legal entity whose assets are available first and foremost to satisfy the claims of its creditors. Of the receivables sold to the Conduits, a portion of the amount due to the Seller is deferred until the ultimate collection of the underlying receivables. During the six months ended June 30, 2010, we received total consideration of $2,199.3 million related to accounts receivable sold under the securitization program, including $726.1 million of cash up front from the sale of the receivables, an additional $1,377.5 million of cash upon the collection of the underlying receivables, and $95.7 million that had not been collected at June 30, 2010 and was recorded at fair value which approximates carrying value. The reduction in accounts receivable as a result of securitization activity with the Conduits was $216.4 million at June 30, 2010 and $254.6 million at December 31, 2009.

     The securitization activity has been reflected in the unaudited condensed consolidated statements of cash flows as operating activity because both the cash received from the Conduits upon sale of receivables as well as the cash received from the Conduits upon the ultimate collection of receivables are not subject to significantly different risks given the short-term nature of our trade receivables. We recorded expense associated with securitization transactions of $0.5 million and $1.0 million for the three months ended June 30, 2010 and 2009, respectively, and $1.2 million and $2.3 million for the six months ended June 30, 2010 and 2009, respectively.

     Other Off-Balance Sheet Arrangements. In June 2010, we established a $60 million line of credit facility for our Singapore coal trading office to purchase coal. There were no amounts drawn against the facility at June 30, 2010.

     There were no other material changes to our off-balance sheet arrangements during the three months ended June 30, 2010. See Note 14 to our unaudited condensed consolidated financial statements for a discussion of our guarantees. Our off-balance sheet arrangements are discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in Note 19 to our consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2009.

Critical Accounting Policies and Estimates

     Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based upon our financial statements, which have been prepared in accordance with U.S. GAAP. We are also required under U.S. GAAP to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an ongoing basis, we evaluate our estimates. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates.

     Our critical accounting policies are discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2009. Our critical accounting policies remained unchanged at June 30, 2010. The following provides additional information around Level 3 fair value measurements.

     Level 3 Fair Value Measurements. In accordance with the “Fair Value Measurements and Disclosures” topic of the Financial Accounting Standards Board Accounting Standards Codification, we evaluate the quality and reliability of the assumptions and data used to measure fair value in the three hierarchy Levels 1, 2 and 3. Commodity swaps and options and physical commodity purchase/sale contracts transacted in less liquid markets or contracts, such as long-term arrangements, with limited price availability were classified in Level 3. Indicators of less liquid markets are those with periods of low trade activity or when broker quotes reflect wide pricing spreads. Generally, these instruments or contracts are valued using internally generated models that include forward pricing curve quotes from one to three reputable brokers. Our valuation techniques also include basis adjustments for heat rate, sulfur and ash content, port and freight costs, and credit and

46

nonperformance risk. We validate our valuation inputs with third-party information and settlement prices from other sources where available. We also consider credit and nonperformance risk in the fair value measurement by analyzing the counterparty’s exposure balance, credit rating and average default rate, net of any counterparty credit enhancements (e.g., collateral), as well as our own credit rating for financial derivative liabilities.

     We have consistently applied these valuation techniques in all periods presented, and believe we have obtained the most accurate information reasonably available for the types of derivative contracts held. Valuation changes from period to period for each level will increase or decrease depending on: (i) the relative change in fair value for positions held, (ii) new positions added, (iii) realized amounts for completed trades, and (iv) transfers between levels. Our coal trading strategies utilize various swaps and derivative physical contracts. Periodic changes in fair value for purchase and sale positions, which are executed to lock in coal trading spreads, occur in each level and therefore the overall change in value of our coal-trading platform requires consideration of valuation changes across all levels.

     Our Level 3 net financial assets represented 9.8% and 5.0% of our total net financial assets as of June 30, 2010 and December 31, 2009, respectively. See Note 12 to our unaudited condensed consolidated financial statements for additional information regarding fair value measurements.

Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented

     See Note 2 to our unaudited condensed consolidated financial statements for a discussion of newly adopted accounting standards and accounting standards not yet implemented.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

     There have been no material changes in market risk from the information provided in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of our Annual Report on Form 10-K for the year ended December 31, 2009.

Item 4. Controls and Procedures.

     Our disclosure controls and procedures are designed to, among other things, provide reasonable assurance that material information, both financial and non-financial, and other information required under the securities laws to be disclosed is accumulated and communicated to senior management, including the principal executive officer and principal financial officer, on a timely basis. Our Chief Executive Officer and our Chief Financial Officer have evaluated our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of June 30, 2010, and have concluded that such controls and procedures are effective to provide reasonable assurance that the desired control objectives were achieved.

     Additionally, during the most recent fiscal quarter, there have been no changes to our internal control over financial reporting that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

47

PART II — OTHER INFORMATION

Item 1. Legal Proceedings.

     See Note 13 to the unaudited condensed consolidated financial statements included in Part I, Item 1 of this report relating to certain legal proceedings, which information is incorporated by reference herein.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

     Our Board of Directors has authorized a share repurchase program of up to $1 billion of the then outstanding shares of our common stock. The repurchases may be made from time to time based on an evaluation of our outlook and general business conditions, as well as alternative investment and debt repayment options. Our Chairman and Chief Executive Officer also has the authority to direct us to repurchase up to $100 million of our common stock outside the share repurchase program. The repurchase program does not have an expiration date and may be discontinued at any time. Through June 30, 2010, we have made repurchases of 7.7 million shares at a cost of $299.6 million ($199.8 million and $99.8 million in 2008 and 2006, respectively), leaving $700.4 million available for share repurchases under the program.

							Maximum Dollar
							Value that May
					Total Number of		Yet Be Used to
	Total				Shares Purchased		Repurchase Shares
	Number of		Average		as Part of Publicly		Under the Publicly
	Shares		Price per		Announced		Announced Program
Period	Purchased(1)		Share		Program		(In Millions)
April 1 through April 30, 2010		2,051	$	45.44		—	$	700.4
May 1 through May 31, 2010		—		—		—		700.4
June 1 through June 30, 2010		1,310		39.80		—		700.4
Total		3,361	$	43.24		—

⁽¹⁾ Represents shares withheld to cover the withholding taxes upon the vesting of restricted stock.

Item 5. Other Information.

     Mine Safety Disclosures

     Our goal is to provide a workplace that is incident free. We believe that it is our responsibility to our employees to provide a superior safety and health environment. We seek to implement this goal by: training employees in safe work practices; openly communicating with employees; establishing, following and improving safety standards; involving employees in safety processes; and recording, reporting and investigating accidents, incidents and losses to avoid reoccurrence. As part of our training, we collaborate with the Mine Safety and Health Administration (MSHA) and other government agencies to identify and test promising safety technologies.

      We are also partnering with several companies and governmental agencies to pursue new technologies that have the potential to improve our safety performance and provide better safety protections for our miners. We have signed letters of intent to field test a new mine emergency vehicle under development by outside companies. We will begin installation of a new communications and tracking system at our U.S. underground mines, which will allow persons on the surface to determine the location of and communicate with all persons underground. In addition, we are exploring the use of proximity detection and collision avoidance systems to enhance the safety around our large equipment fleets.

     In the second quarter of 2010, we voluntarily idled the majority of our mines for one day to allow for interactive safety discussions with our employees, local and federal agency representatives and management, and to provide additional comprehensive training on accident prevention, violation awareness and reduction and emergency preparedness. In the third quarter of 2010, we expect that the remainder of our mines will complete the same training.

     Through our safety tracking system, we monitor safety performance using incidence rate and violations per inspection day. For the six months ended June 30, 2010, our U.S. incidence rate was 2.00, a 4% improvement over the same period in the prior year, and our U.S. violations per inspection day was 1.15, a 24% improvement over the same period in the prior year.

48

     Following passage of The Mine Improvement and New Emergency Response Act of 2006, MSHA significantly increased the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. There has also been an increase in the dollar penalties assessed for citations issued over the past two years.

     The following disclosures are provided pursuant to the recently enacted Dodd-Frank Act, which requires certain disclosures by companies required to file periodic reports under the Securities Exchange Act of 1934, as amended, that operate coal mines regulated under the U.S. Federal Mine Safety and Health Act of 1977 (the Mine Act). Under the Dodd-Frank Act, the SEC is authorized to issue rules and regulations to carry out the purposes of these provisions, but has not done so as of the date of this report. While we believe the following disclosures meet the requirements of the Dodd-Frank Act, it is possible that any rule making by the SEC will require disclosures to be presented in a form that differs from the following. The disclosures reflect U.S. mining operations only as the requirements of the Dodd-Frank Act do not apply to our mines operated outside the U.S.

     Mine Safety Information. Whenever MSHA believes that a violation of the Mine Act, any health or safety standard, or any regulation has occurred, it may issue a citation which describes the violation and fixes a time within which the operator must abate the violation. In some situations, such as when MSHA believes that conditions pose a hazard to miners, MSHA may issue an order removing miners from the area of the mine affected by the condition until hazards are corrected. Whenever MSHA issues a citation or order, it generally proposes a civil penalty, or fine, as a result of the violation, that the operator is ordered to pay. Citations and orders can be contested and appealed, and as part of that process, are often reduced in severity and amount, and are sometimes dismissed. The number of citations, orders and proposed assessments vary depending on the size and type (underground or surface) of the mine as well as by the MSHA inspector(s) assigned to that mine.

     The table that follows reflects citations and orders issued to us by MSHA during the three months ended June 30, 2010, as reflected in our safety tracking system. Due to timing and other factors, the data in our system may not agree with the mine data retrieval system maintained by MSHA. The proposed assessments for the three months ended June 30, 2010 were taken from the MSHA system as of August 4, 2010.

     Additional information follows about MSHA references used in the table.

• Section 104 Citations: The total number of violations received from MSHA under section 104 of the Mine Act, which includes citations for health or safety standards that could significantly and substantially contribute to a serious injury if left unabated.

• Section 104(b) Orders: The total number of orders issued by MSHA under section 104(b) of the Mine Act, which represents a failure to abate a citation under section 104(a) within the period of time prescribed by MSHA. This results in an order of immediate withdrawal from the area of the mine affected by the condition until MSHA determines that the violation has been abated.

• Section 104(d) Citations and Orders: The total number of citations and orders issued by MSHA under section 104(d) of the Mine Act for unwarrantable failure to comply with mandatory health or safety standards.

• Section 110(b)(2) Violations: The total number of flagrant violations issued by MSHA under section 110(b)(2) of the Mine Act.

• Section 107(a) Orders: The total number of orders issued by MSHA under section 107(a) of the Mine Act for situations in which MSHA determined an imminent danger existed.

49

Three Months Ended June 30, 2010

					Section						($)
	Section		Section		104(d)		Section		Section		Proposed
	104		104(b)		Citations and		110(b)(2)		107(a)		MSHA
Mine (1)	Citations		Orders		Orders		Violations		Orders		Assessments		Fatalities
											(in thousands)
Western U.S. Mining
Caballo		2		—		—		—		—		1.0		—
El Segundo		—		—		—		—		—		—		—
Kayenta		1		—		—		—		—		—		—
Lee Ranch		1		—		—		—		—		—		—
North Antelope Rochelle		3		—		—		—		—		52.5		—
Rawhide		4		—		—		—		—		1.8		—
Twentymile (Foidel Creek)		60		—		—		—		1		49.3		—
Midwestern U.S. Mining
Air Quality		108		—		6		—		—		91.3		—
Bear Run		2		—		—		—		—		0.3		—
Cottage Grove (Wildcat Hills-Cottage Grove Pit)		2		—		—		—		—		0.6		—
Farmersburg		3		—		—		—		—		—		—
Francisco Underground		102		—		—		—		—		58.3		—
Francisco Surface(2)		2		—		—		—		—		—		—
Gateway		91		—		3		—		1		142.8		—
Midwest Repair Facility (Columbia Maintenance Services)		3		—		—		—		—		0.3		—
Somerville Central		11		—		—		—		—		5.5		—
Somerville North		—		—		—		—		—		—		—
Somerville South		—		—		—		—		—		—		—
Viking (Viking-Corning and Knot Pit)		28		—		—		—		—		35.4		—
Wildcat Hills Underground		90		—		—		—		—		40.9		—
Willow Lake (Willow Lake Portal and Central Preparation Plant)		192		—		4		—		—		317.5		—

(1)

The definition of mine under section 3 of the Mine Act includes the mine, as well as other items used in, or to be used in, or resulting from, the work of extracting coal, such as land, structures, facilities, equipment, machines, tools, and coal preparation facilities. Unless otherwise indicated, any of these other items associated with a single mine have been aggregated in the totals for that mine. Also, there are instances where the mine name per the MSHA system differs from the mine name utilized by us. Where applicable, we have parenthetically listed the name(s) of the mine per the MSHA system.

(2)

The Francisco Surface Mine was closed in the fourth quarter of 2009.

     Pattern or Potential Pattern of Violations. During the three months ended June 30, 2010, none of the mines operated by us received written notice from MSHA of (a) a pattern of violations of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of coal mine health or safety hazards under section 104(e) of the Mine Act or (b) the potential to have such a pattern.

     Pending Legal Actions. The Federal Mine Safety and Health Review Commission (the Commission) is an independent adjudicative agency that provides administrative trial and appellate review of legal disputes arising under the Mine Act. These cases may involve, among other questions, challenges by operators to citations, orders and penalties they have received from MSHA, or complaints of discrimination by miners under Section 105 of the Mine Act. The following is a brief description of the types of legal actions that may be brought before the Commission.

• Contests of Citations and Orders – A contest proceeding may be filed with the Commission by operators, miners or miners’ representatives to challenge the issuance of a citation or order issued by MSHA.

• Contests of Proposed Penalties (Petitions for Assessment of Penalties) – A contest of a proposed penalty is an administrative proceeding before the Commission challenging a civil penalty that MSHA has proposed for the violation contained in a citation or order.

• Complaints for Compensation – A complaint for compensation may be filed with the Commission by miners entitled to compensation when a mine is closed by certain withdrawal orders issued by MSHA. The purpose of the proceeding is to determine the amount of compensation, if any, due miners idled by the orders.

• Complaints of Discharge, Discrimination or Interference – A discrimination proceeding is a case that involves a miner’s allegation that he or she has suffered a wrong by the operator because he or she engaged in some type of activity protected under the Mine Act, such as making a safety complaint.

• Temporary Reinstatement Proceedings – Temporary reinstatement proceedings involve cases in which a miner has filed a complaint with MSHA stating he or she has suffered discrimination and the miner has lost his or her position.

• Emergency Response Plan (ERP) Dispute Proceedings – ERP dispute proceedings are cases brought before the Commission when an operator is issued a citation because it has not agreed to include a certain provision in its ERP.

50

The table that follows presents information by mine regarding pending legal actions before the Commission at June 30, 2010. Each legal action is assigned a docket number by the Commission and may have as its subject matter one or more citations, orders, penalties or complaints.

	Legal
Mine	Actions
Western U.S. Mining
Caballo		1
El Segundo		2
Kayenta		7
Lee Ranch		2
North Antelope Rochelle		11
Rawhide		—
Twentymile (Foidel Creek)		55
Midwestern U.S. Mining
Air Quality		12
Bear Run		—
Cottage Grove (Wildcat Hills-Cottage Grove Pit)		—
Farmersburg		—
Francisco Underground		—
Francisco Surface		—
Gateway		—
Midwest Repair Facility (Columbia Maintenance Services)		—
Somerville Central		1
Somerville North		—
Somerville South		—
Viking (Viking-Corning and Knot Pit)		—
Wildcat Hills Underground		—
Willow Lake (Willow Lake Portal and Central Preparation Plant)		16

Item 6. Exhibits.

     See Exhibit Index at page 53 of this report.

51

SIGNATURE

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	PEABODY ENERGY CORPORATION
Date: August 6, 2010	By:	/s/ MICHAEL C. CREWS
		Michael C. Crews
		Executive Vice President and Chief Financial Officer (On behalf of the registrant and as Principal Financial Officer)

52

EXHIBIT INDEX

The exhibits below are numbered in accordance with the Exhibit Table of Item 601 of Regulation S-K.

Exhibit
No.		Description of Exhibit
	3.1	Third Amended and Restated Certificate of Incorporation of the Registrant, as amended (Incorporated by reference to Exhibit 3.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008).
	3.2	Amended and Restated By-Laws of the Registrant (Incorporated by reference to Exhibit 3.1 of the Registrant’s Current Report on Form 8-K filed on September 16, 2008).
	10.1	Second Amendment to Third Amended and Restated Receivables Purchase Agreement, dated as of May11, 2010, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, the various Sub-Servicers listed on the signature pages thereto, all Conduit Purchasers listed on the signature pages thereto, all Related Committed Purchasers listed on the signature pages thereto, all Purchaser Agents listed on the signature pages thereto, all LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as LC Bank (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on May 17, 2010).
	10.2	Credit Agreement, dated as of June 18, 2010, by and among the Company, Bank of America, N.A., as administrative agent, swing line lender and L/C issuer, and Banc of America Securities LLC, Citigroup Global Markets, Inc. and HSBC Securities (USA) Inc., as joint lead arrangers and joint book managers, and the lenders named therein (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on June 24, 2010).
	31.1*	Certification of periodic financial report by Peabody Energy Corporation’s Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31.2*	Certification of periodic financial report by Peabody Energy Corporation’s Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	32.1*	Certification of periodic financial report pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Peabody Energy Corporation’s Chief Executive Officer.
	32.2*	Certification of periodic financial report pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Peabody Energy Corporation’s Chief Financial Officer.
	101**	Interactive Data File (Form 10-Q for the quarterly period ended June 30, 2010 furnished in XBRL). Users of this data are advised in accordance with Rule 406T of Regulation S-T promulgated by the Securities and Exchange Commission that this Interactive Data File is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections. The financial information contained in the XBRL-related documents is “unaudited” and “unreviewed.”

*	Filed herewith.
**	Submitted herewith.

53

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Gregory H. Boyce, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Peabody Energy Corporation (“the registrant”);
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 6, 2010

/s/ Gregory H. Boyce  

Gregory H. Boyce 

Chairman and Chief Executive Officer 

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Michael C. Crews, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Peabody Energy Corporation (“the registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 6, 2010

/s/ Michael C. Crews  

Michael C. Crews 

Executive Vice President and Chief
Financial Officer 

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
(18 U.S.C. SECTION 1350)

I, Gregory H. Boyce, Chairman and Chief Executive Officer of Peabody Energy Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)	the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2010 (the “Periodic Report”) which this statement accompanies fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
(2)	information contained in the Periodic Report fairly presents, in all material respects, the financial condition and results of operations of Peabody Energy Corporation.

Dated: August 6, 2010

/s/ Gregory H. Boyce  

Gregory H. Boyce 

Chairman and Chief Executive Officer 

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
(18 U.S.C. SECTION 1350)

I, Michael C. Crews, Executive Vice President and Chief Financial Officer of Peabody Energy Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)	the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2010 (the “Periodic Report”) which this statement accompanies fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
(2)	information contained in the Periodic Report fairly presents, in all material respects, the financial condition and results of operations of Peabody Energy Corporation.

Dated: August 6, 2010

/s/ Michael C. Crews  

Michael C. Crews 

Executive Vice President and Chief
Financial Officer